DOWNHOLE CASING TOOL WITH INTEGRATED TOE PREPPER AND METHOD OF USING SAME

BACKGROUND

The present disclosure relates generally to oilfield technology. More specifically, the present disclosure relates to techniques for downhole perforating, casing, and testing.

Wellsite operations are performed to locate and access subsurface targets, such as valuable hydrocarbons. Drilling equipment is positioned at the surface and downhole drilling tools are advanced into the subsurface formation to form wellbores. Once drilled, casing may be inserted into the wellbore and cemented into place to complete the well. Examples of casing techniques are provided U.S. Pat./Application Nos. 9976384, 10683734, 20120318507, and 20150184489. Once the well is completed, tubing may be deployed through the casing and into the wellbore to produce fluid to the surface for capture.

During the wellsite operations, various downhole tools, may be deployed into the earth to perform various procedures, such as perforation, fracking, injection, plugging, etc. Examples of downhole tools are provided in U.S. Pat./Application Nos. 20200024935; 10507433; 20200277837; 20190242222; 20190234189; 10309199; 20190127290; 20190086189; 20190242209; 20180299239; 20180224260; 9915513; 20180038208; 9822618; 9605937; 20170074078; 9581422; 20170030693; 20160356132; 20160061572; 8960093; 20140033939; 8267012; 6520089; 20160115753; 20190178045; and 10365079, the entire contents of which are hereby incorporated by reference herein to the extent not inconsistent with the present disclosure. During the wellsite operations, fluids may be passed through the wellbore for fracking, injection, and testing. Examples of fluid techniques are provided U.S. Pat./Application Nos. 10301909 and 10961818. The downhole tools may also be activated to perform the wellsite operations. Examples of techniques for activating are provided in U.S. Pat./Application Nos. 10,036,236; 20200072029; 20200048996; and 20160115753 the entire contents of which is hereby incorporated by reference herein to the extent not inconsistent with the present disclosure.

Despite the advancements in downhole technology, there remains a need for facilitating perforating, casing, and testing in a wellbore. The present disclosure is directed at providing such needs.

SUMMARY

In at least one aspect, the disclosure relates to a toe prepper for a downhole casing tool. The downhole casing tool comprises a casing string positionable in a wellbore penetrating a subterranean formation. The toe prepper comprises a ball sub and port sub. The ball sub comprises a ball joint, a ball, and a ball seat. The ball joint is operatively connectable to the casing string. The ball j oint has a tubular body with a passage therethrough. The tubular body has an inner surface defining a receptacle. The ball is disposable through the passage of the ball joint. The ball seat is positionable in the receptacle. The ball seat having a ring-shaped body shaped to receivingly support the ball therein. The port sub comprises a port joint, ports, and port plugs. The port joint is operatively connectable to the ball sub. The port sub has a tubular body with the passage therethrough. The ports extend through the port joint. The port plugs are positioned in the ports. The port plugs comprise a plug material dissolvable upon exposure to a fluid. The ball and the ball seat are shaped to prevent passage of fluid from the ball sub and into the port sub until activated by the fluid to release the ball from the ball seat.

In another aspect, the disclosure relates to a downhole casing tool comprising a casing string and the toe prepper. The casing string comprises a plurality of casing joints threadedly connected together with the passage extending therethrough. The toe prepper comprises a ball sub and port sub. The ball sub comprises a ball joint, a ball, and a ball seat. The ball joint is operatively connectable to the casing string. The ball joint has a tubular body with a passage therethrough. The tubular body has an inner surface defining a receptacle. The ball is disposable through the passage of the ball joint. The ball seat is positionable in the receptacle. The ball seat having a ring-shaped body shaped to receivingly support the ball therein. The port sub comprises a port joint, ports, and port plugs. The port joint is operatively connectable to the ball sub. The port sub has a tubular body with the passage therethrough. The ports extend through the port joint. The port plugs are positioned in the ports. The port plugs comprise a plug material dissolvable upon exposure to a fluid. The ball and the ball seat are shaped to prevent passage of fluid from the ball sub and into the port sub until activated by the fluid to release the ball from the ball seat.

In yet another aspect, the disclosure relates to a method of fracking a formation penetrated by a wellbore. The method comprises running a casing tool comprising a toe prepper into a wellbore. The toe prepper comprises a ball sub with a ball seat therein and a port sub with ports therethrough. The method further comprises dropping a ball into the downhole casing tool and allowing the ball to seat in the ball seat, and injecting fluid into the formation surrounding the wellbore by pumping the fluid through the downhole casing tool until the ball is unseated from the ball seat and the fluid dissolves port plugs in the ports such that the ports open to permit passage of the fluid into the formation.

In at least one aspect, the disclosure relates to toe prepper. The toe prepper comprises: a ball sub with a ball and a ball seat; and a port sub. In another aspect, the disclosure relates to a downhole casing tool comprising: casing joints and the toe prepper. In yet another aspect, the disclosure relates to a method of casing using the toe prepper. Finally, in another aspect, the disclosure relates to a toe prepper, a downhole casing tool, and/or method as described in the specification, claims, and/or drawings.

This Summary is not intended to be limiting and should be read in light of the entire disclosure including text, claims and figures herein.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the above recited features and advantages of the present disclosure can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended drawings. The appended drawings illustrate example embodiments and are, therefore, not to be considered limiting of its scope. The figures are not necessarily to scale and certain features, and certain views of the figures may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.

FIG. 1 is a schematic view of a wellsite with surface and downhole equipment, the downhole equipment comprising a downhole casing tool including a toe prepper.

FIG. 2 is a schematic longitudinal, cross-sectional view of the toe prepper, the toe prepper including a ball sub and port subs.

FIG. 3 is a schematic longitudinal, cross-sectional view of the ball sub before activation.

FIG. 4 is a schematic longitudinal, cross-sectional view of the ball sub after activation.

FIG. 5 is a schematic longitudinal, cross-sectional view of the port sub.

FIG. 6 is a flow chart depicting a method of fracking a formation.

DETAILED DESCRIPTION

The description that follows includes exemplary apparatus, methods, techniques, and/or instruction sequences that embody techniques of the present subject matter. However, it is understood that the described embodiments may be practiced without these specific details.

The present disclosure relates to a toe prepper for a downhole casing tool. The downhole tool includes a casing string with the toe prepper integrated with (e.g., connected about) the casing string. The casing string includes a series of casing joints connected end to end in series to form an elongate casing string for lining the wellbore. The casing string may have various devices, such as the toe prepper, positioned in (or between) portions of the casing string to perform various downhole operations.

The toe prepper includes a toe string connected about the casing string. The toe prepper also includes a ball (or flow) sub and a port sub positioned in the toe string. The ball sub includes a ball joint with a ball seat therein, and a ball releasably positioned in the ball seat. The ball may be selectively releasable by pressurizing the ball sub to allow the ball to pass from the ball seat and downhole through the toe casing string, or by dissolving a portion of the ball to pass through the ball seat.

The port sub includes a port tube with ports therethrough, and removable (e.g., dissolvable) port plugs positioned in the ports. The removable ports may be positioned through the port tube to define perforations for passing fluid through the casing string and into a formation surrounding the wellbore. The toe prepper may also include other removable (e.g., dissolvable) portions. For example, at least a portion of the ball, the ball seat, and the port plugs may be dissolvable by a fluid (e.g., fresh water, salt water, acid, wellbore fluid, injection fluid, etc.) to facilitate unseating of the ball and/or opening of the perforations.

The toe prepper may be integrated into the casing string to perform various downhole operations. For example, the port tube may be pre-perforated with the ports to facilitate perforation of the wellbore. For such perforation operations, the ports in the port tube may be configured to provide multiple perforation paths for injecting the fluid into the formation surrounding the wellbore (e.g., fracking). The port sub may incorporate perforating functions of a perforating tool into the casing tool, thereby eliminating the need for sending an additional perforating tool to be run into the wellbore to form the perforations.

The port sub may also be used for fracking/injection operations. The port sub may have the ports with port plugs that dissolve to allow the fluid (e.g., injection fluid) to be injected through the ports and into the formation, thereby eliminating the need for running a separate fracking/injection tool into the well on coiled tubing to pump injection fluid into the formation. The toe prepper may also be used for performing various tests (e.g., a pre-frac casing test, a pressure test, post cement casing integrity test,), thereby eliminating additional tool runs into the wellbore by testing tools.

The present disclosure seeks to provide one or more of the following features, among others: simplicity of design, simple moving parts, reduced numbers of moving parts, economical design, field adjustability, adjustable dimensions (e.g., spacing, placement, and number of ports), cost effective, multiple perforation ports, perforations arranged to stimulate perforation patterns of perforating gun, integrated/combined/eliminated tools and/or runs, dissolvable components, etc.

FIG. 1 is a schematic view of a wellsite 100 with surface equipment 102a and downhole equipment 102b. The downhole equipment 102b comprises a downhole casing tool 104 including a toe prepper 111. The wellsite 100 may be any wellsite positioned about a subterranean formation 101, such as an unconventional formation (e.g., shale) with a reservoir (e.g., oil, gas, water) therein.

The surface equipment 102a is positioned about a wellbore 106. The wellbore 106 may have been drilled using a drilling rig with a downhole drilling tool (not shown). Other downhole tools may be deployed into the wellbore 106, such as a testing tool for taking downhole measurements. A casing tool may be advanced by the drilling rig into the wellbore 106, and cemented into place within the wellbore 106. The drilling rig may be removed and production equipment may be installed after drilling rig operations are completed. A downhole coiled tubing tool, such as a perforating and/or injecting tool (not shown), may also have been deployed into the wellbore 106 to perforate and/or frac the formation 101. Techniques for drilling, testing, casing, perforating, injecting, and performing other downhole operations may be found in the patents/applications previously incorporated by reference herein.

In the example shown in FIG. 1, the surface equipment 102a includes a wellhead 107, a Christmas tree 108, a surface unit 110, and a pump truck 112. The wellhead 107 may include a flanged support positioned at an opening of the wellbore 106. The Christmas tree 108 may be a conventional production device positioned about the wellhead 107. The Christmas tree 108 may be coupled to the surface unit 110 and the pump truck 112 for operation therewith.

The surface unit 110 may be operatively connected (e.g., electrically, pneumatically, and/or mechanically coupled) to the Christmas tree 108 as schematically shown by link 115. The surface unit 110 may be used for operating equipment at the wellsite 100. The surface unit 110 may include conventional equipment used for operating the surface equipment 102a and/or the downhole equipment 102b, such as hydraulic devices, electronic devices, and/or processors (e.g., central processing units (CPUs)).

The pump truck 112 may be a pump truck or other device capable of supporting fluid at the wellsite 100. In this example, the pump truck 112 is a mobile truck carrying a fluid tank 114. The fluid tank 114 may house fluid 117, such as fresh water, salt water, acid, wellbore fluid, injection fluid, etc. The fluid tank 114 is coupled by a conduit 116 to the wellhead 107. A pump 121 and a valve 123 are positioned along the conduit 116 for selectively transporting the fluid 117 from the fluid tank 114 and into the wellbore 106. The Christmas tree 108, the surface unit 110, the pump truck 112, the pump 121, and/or other fluid control devices (e.g., valves) may be used to manipulate the fluid flow into the wellbore 106.

The downhole equipment 102b includes the downhole casing tool 104 suspended from the wellhead 107 and advanced into the wellbore 106 to form a lining along a surface of the wellbore 106. The casing tool 104 may be secured in the wellbore 106 by pumping cement through the casing tool 104 and into the wellbore 106 to form a seal between the casing tool 104 and a wall of the wellbore 106.

In the example shown in FIG. 1, the casing tool 104 includes a casing string 118, a float assembly 119, and the toe prepper 111. The casing tool 104 may also include other devices (not shown), such as packers, hangers, sleeves, valves, plugs, collars, etc. The casing string 118 is made of a series of casing joints 120 connected end-to-end in series to form an elongate tubular member. The casing joints 120 may be tubular metal members with threaded ends connectable to adjacent casing joints 120. The casing string 118 may have a passage 122 for flow of the fluid 117 therethrough. The casing joints 120 may be conventional casing joints made of a metal (e.g., steel or metal alloy) and used for casing wellbores. Examples of casing techniques are described in the patent/applications incorporated by reference herein.

The float assembly 119 is positioned at a downhole end of the casing tool 104. The float assembly includes an isolation plug 124 and a float shoe 126. The isolation plug 124 may be any plugging device, such as a cement plug capable of fluidly isolating a portion of the wellbore 106. The float shoe 126 is connected to a downhole end of the isolation plug 124. The float shoe 126 may be a conventional float device capable of guiding the casing tool 104 as it passes through the wellbore 106. The float assembly 119 may include other devices for supporting the casing tool 104 and/or for facilitating casing operations. Examples of plugs and float techniques are described in the patent/applications incorporated by reference herein.

The toe prepper 111 is positioned between the casing string 118 and the float assembly 119. The toe prepper 111 may include a toe string 128, a ball sub 130, and a port sub 132. The toe string 128 may be threadedly connected to a downhole end of the casing string 118 and an uphole end of the isolation plug 124.

The toe string 128 may include a series of toe joints 134 connected end to end to form an elongate tubular member with the passage 122 extending therethrough. The toe joints 134 may be tubular metal members similar to the casing joints 120. The toe string 128 may also be part of, or incorporated with, the casing string 118. One or more of the toe joints 134 may be a casing joint 120, or one or more of the toe joints 134 may include or be coupled to the casing joints 120. The toe joints 134 may also be interspersed along the casing string 118 between one or more of the casing joints 120. The toe joints 134 may also include other tubular members, such as rings, sleeves, and/or joints, threadedly connectable together.

The ball sub 130 and the port sub 132 are positioned along the toe string 128. The ball sub 130 and the port sub 132 may be positioned in the toe joints 134 or connected between the toe joints 134. The ball sub 130 may include a flow device 136 capable of selectively blocking the passage 122 to selectively block flow of the fluid 117. The flow device 136 may be selectively activated by the fluid 117 to generate sufficient pressure to open and allow fluid to flow through the port sub 132 as schematically shown by the longitudinal arrows and is described further herein. The port subs 132 may be provided with devices capable of allowing the fluid 117 to flow through the toe string 128 and to the formation 101 surrounding the wellbore 106 as schematically shown by the radial arrows and is described further herein.

The ball sub 130, the flow device 136, and the port sub 132 may be used to temporarily block the fluid 117 from passing through the toe prepper 111. This temporary block may be selectively released as needed by passing the fluid 117 through the toe prepper 111, thereby allowing casing and/or downhole operations to be performed. For example, this temporary block may be used to allow fluid buildup in the casing tool 104 for performing downhole testing, such as a pre-frac casing test, a pressure test, post cement casing integrity test, and/or other downhole tests to assure casing and/or downhole operations. The temporary block may then be released to allow fluid to flow through the toe string 128 and into the formation 101.

FIG. 2 is a schematic longitudinal, cross-sectional view of the toe prepper 111. As shown in this example, the toe prepper 111 includes the ball sub 130 and four of the port subs 132. As shown by this figure, the ball sub 130 includes a ball joint 240a, a ball seat 240b, and a ball 240c.

The ball joint 240a is a tubular metal member with threaded ends connectable to the casing joint 120 at a downhole end of the casing string 118 (FIG. 1). The ball seat 240b may be supported in (or connected to) the ball joint 240a. The ball 240c is releasably supported in the ball seat 240b of the ball joint 240a. The ball 240c may be dropped through the casing tool 104 and seated in the ball seat 240b. The ball 240c may be dropped into the casing tool 104 after deploying the casing tool 104 into the wellbore 106 (e.g., after cementing the casing tool in place).

The port subs 132 each include a port joint 242a and port plugs 242b. The port joint 242a is a tubular metal member with threaded ends connectable to the ball joint 240a, the casing joints 120, the toe joints 134, and/or the float assembly 119 (FIG. 1). The port joint 242a has ports (perforation holes) 244 therethrough. One or more of the ports 244 may be provided. The ports 244 may be positioned about the port joint 242a to define flow paths for passage of the fluid 117 from inside of the port sub 132 and into the surrounding formation 101. The port plugs 242b may be positioned in the ports 244 to close the ports 244 and prevent the fluid from passing therethrough.

In the example shown in FIG. 2, the toe joints 134 are connected between the ball sub 130 and each of the port subs 132. The toe joints 134 are spaced at intervals along the toe prepper 111 to define spacing between the port subs 132. This spacing may be, for example, about 10 feet (3.05 m) or other spacing as needed to define perforations along the wellbore 106.

The ball joint 240a and/or the port joints 242a may be coupled to or incorporated with the casing joints 120 and/or the toe joints 134. The ball joints 240a, the port joints 242a, the casing joints 120, and/or the toe joints 134 may be provided with various features, such as threaded ends (e.g., pin and/or box ends) capable of threaded connection with an adjacent joint. The ball joint 240a, the port joints 242a, and/or the toe joints 134 may also include other features, such as shoulders, steps, surfaces (e.g., flat, smooth, textured, coated, etc.) to facilitate the casing operations. One or more of the ball joints 240a and the port joints 242a may be the same as, or different from, the casing joints 120 and/or each other. Additional joint devices, such as rings, sleeves, and/or joints, etc., may also be included along the toe string 128.

Part or all of the ball 240c and the port plugs 242b may be made of a dissolvable material, such as magnesium. This material may dissolve upon contact with the fluid 117, or over time after contact with the fluid 117. The ball 240c may be at least partially dissolvable upon contact with the fluid 117 to activate the ball sub 130 as is described further herein. The port plugs 242b may be at least partially dissolvable upon contact with the fluid 117 to selectively open the ports 244 as is described further herein.

FIGS. 3 and 4 show detailed views of a portion of the toe string 128 depicting example versions of the ball sub 130. FIG. 3 is a schematic longitudinal, cross-sectional view of the ball sub 130 before activation. FIG. 4 is a schematic longitudinal, cross-sectional view of the ball sub 130 after activation. As shown by these figures, the ball sub 130 may be selectively activated by the fluid 117 to block and/or release the fluid 117 through the ball sub 130.

As shown in FIG. 3, the ball joint 240a has threaded box ends 346a connectable to corresponding threaded pin ends 346b of the casing joint 120 and the toe joint 134. An inner surface 348 of the ball joint 240a may be shaped to support the ball seat 240b therein. The inner surface 348 of the ball joint 240a may define a receptacle 350 capable of receivingly supporting the ball seat 240b therein. For example, the inner surface 348 may be stepped to define the receptacle 350 such that the ball seat 240b is releasably supported in the ball joint 240a.

The ball seat 240b is a ring-shaped member positioned along the inner surface 348 of the ball joint 240a in the receptacle 350. The ball seat 240b may be a flexible member made of an elastomeric or other material capable of supporting the ball 240c in the ball sub 130 and/or capable of supporting the ball seat 240b in the ball joint 240a. The ball seat 240b may be capable of releasably supporting the ball 240c and/or the ball seat 240b to allow selective movement of the ball 240c and/or the ball seat 240b upon activation by the fluid 117.

Referring to FIGS. 1, 3, and 4, the toe prepper 111 may be activated by releasing the ball 240c from the ball seat 240b using the fluid 117. The pump 121 may pump and/or the valve 123 may open at the surface to initiate or increase flow of the fluid 117 through the casing string 118 and the toe prepper 111. The ball seat 240b may also be activatable under fluid pressure created by a buildup of the fluid 117 in the toe string 128. The flow of the fluid 117 may be used in conjunction with various features of the ball sub 130 to cause the ball 240c to move through the ball joint 240a.

For example, the ball seat 240b may expand such that the ball seat 240b is compressed against the inner surface 348 in the receptacle 350. Under this compression, an inner diameter of the ball seat 240b may expand to allow the ball 240c to fall therethrough, thereby releasing the ball 240c and allowing the fluid to pass through the toe prepper 111.

In another example, upon passage of a sufficient amount or rate of the fluid 117 through the toe string 128, the ball seat 240b may be releasable from the receptacle 350 and movable (e.g., slidable) downhole along the ball joint 240a as indicated by the dual arrows. The ball sub 130 may also include a shear ring 349 positioned in the ball joint 240a adjacent to the ball seat 240b. The shear ring 349 may be a ring or c-shaped member positioned in the receptacle 350 between the stepped inner surface 348 and the ball seat 240b.

The shear ring 349 may be a frangible member designed to support the ball seat 240b in position until a minimum fluid pressure is achieved. Application of sufficient pressure by the fluid 117 against the ball 240c may cause the shear ring 349 to break. Upon breaking, the shear ring 349 may allow the ball seat 240b to move from an uphole end of the ball joint 240a of FIG. 3 to a downhole end of the ball joint 240a as shown in FIG. 4. The ball seat 240b may advance downhole until movement is terminated. For example, the ball seat 240b may move to a position adjacent the pin end 346b of the adjacent toe joint 134, or to another position in the toe prepper 111. Upon moving, the ball seat 240b may open wide enough to allow the ball 240c to be released and pass through the ball seat 240b.

Portions of the toe string 128 may be shaped to restrict or allow the ball 240c to pass through the toe string 128. For example, the pin end 346b of the toe joint 134 (or another device within the toe prepper 111) may extend into the passage 122 to act as a stop for the ball seat 240b. Other stops may be provided along the toe prepper 111. In another example, the inner surface 348 of the toe string 128 may also be made substantially smooth to facilitate passage of the ball 240c through the toe string 128.

In another example, the flow of the fluid 117 may release the ball 240c by unseating the ball 240c from the ball seat 240b. The ball 240c may be shaped to fixedly seat in the ball seat 240b in an inactivated position as shown in FIG. 3. When the fluid 117 is passed into the ball sub 130, the fluid 117 may dissolve at least a portion of the ball 240c and activate the ball 240c to pass through the ball seat 240b. As indicated by the dashed circle, the ball 240c may have an outer portion (e.g., coating) made of the dissolvable material that falls away over time upon contact with the fluid 117 (FIG. 3), or the entire ball 240c may be dissolvable upon contact with the fluid 117 (FIG. 4). After the dissolvable material falls away, the outer surface of the ball 240c is removed and the ball 240c has a smaller dimension (e.g., outer diameter). This smaller outer diameter may cause the ball 240c to release (shear out) from the ball seat 240b and fall through the toe string 128 as indicated by the dashed arrow.

In yet another example, the ball 240c may be released by unseating the ball 240c from the ball seat 240b. The ball sub 130 may also be activated by passing the fluid 117 through the ball sub 130 at sufficient pressure to unseat the ball 240c from the ball seat 240b. The fluid pressure may be sufficient to urge the ball 240c downhole through an opening in the ball seat 240b such that the ball 240c falls through the toe string 128 as indicated by the dashed arrow.

Dimensions of the ball sub 130 may be defined to facilitate operation of the ball sub 130. As shown in FIGS. 3 and 4, an inner diameter (JTID) of the toe joint 134 is larger than an outer diameter (BOD) of the ball 240c to allow the ball 240c to pass therethrough, and the inner diameter JTID of the toe joint 134 is smaller than an outer diameter (SOD) of the ball seat 240b to terminate downhole advancement of the ball seat 240b when the ball seat 240b is released from the receptacle 350.

For example, the outer diameter of the ball 240c (BOD) may be about 5.25 inches (13.33 cm), the outer diameter of the ball joint 240a (ODBJ) may be about 6.55 inches (16.64 cm), the inner diameter of the toe joint 134 (TJID) may be about 5.28 inches (13.41 cm), and the outer diameter of the ball seat 240b (SOD) may be greater than about 5.28 inches (13.41 cm) and less than an inner diameter of the flow joint 240a. The dimensions may be adjusted as needed for the wellbore applications, the casing size, the releasability of the ball 240c, the passage of the ball 240c through the toe string 128, etc.

FIG. 5 is a schematic longitudinal, cross-sectional view of the port sub 132. This figure shows features of the port sub 132 in greater detail. As shown in this view, the port joint 242a has a pin end 550a and a box end 550b threadedly connectable to adjacent toe joints 134 (FIG. 2). A body of the port joint 242a between the pin end 550a and the box end 550b has smooth inner and outer surfaces.

The port joint 242a also has one or more ports 244 (e.g., about 4 are shown) therethrough. As shown in FIG. 5, the ports 244 may be aligned horizontally and/or vertically along the port joint 242a, or dispersed about the port joint 242a. The pattern and number of ports 244 may be defined as needed to allow the fluid 117 to flow through the ports 244 and to pass into the formation 101 (FIG. 1).

For example, the ports 244 may be positioned at various depths along 360 degrees about one or more of the port joints 242a. The ports 244 may be arranged to define perforations and along the wellbore 106 that simulates a pattern achieved using a conventional perforating gun. The ports 244 may also be arranged to define flow paths through the port joint 242a and into the formation 101. These ports 244 may be used as passageways for injecting the fluid 117 from the port sub 132 and into the formation 101. This fluid 117 may be passed under pressure through the ports 244 and into the formation 101 to simulate fracking and/or injection into the formation 101.

The port plugs 242b may be disc shaped members corresponding to the shape of the ports 244. The port plugs 242b may be configured (e.g., provided with dimensions) such that the port plugs 242b are receivably supported in the ports 244. The port plugs 242b may be supported by an interference fit, or secured in the ports 244 by support means, such as an adhesive.

The port plugs 242b may be supported in the ports 244 until the fluid 117 engages the port plugs 242b and dissolves at least a portion of the port plugs 242b over time. Under pressure and/or exposure to the fluid 117, the ports 244 may dissolve to create an opening for the flow of the fluid 117 therethrough. The port plugs 242b may be dissolved until enough of the port plugs 242b are sufficiently removed from the ports 244 to allow the fluid 117 to flow through the ports 244 and into the formation 101.

The port sub 132 may have various dimension. For example, an outer diameter of the port joint 242a (PJOD) may be about 6.55 inches (16.64 cm), an inner diameter of the port joint 242a (PJID) may be about 5.3” inches (13.46 cm), and a diameter of the ports 244 (PD) may be about 1.5” inches (3.81 cm). The dimensions may be adjusted as needed for the wellbore applications, the casing size, the desired flow through the ports 244, the time to release fluid through the ports 244, etc.

FIG. 6 is a flow chart depicting a method 600 of fracking a formation. As shown in this flow chart, the method 600 involves 670 running the casing tool with a toe prepper into the wellbore. The casing tool may be deployed into the wellbore using a drilling rig. The method 600 continues with 671 securing the casing tool in the wellbore by pumping cement through the casing tool. After the cement is secured in placed about the casing, the method continues with 672 performing post cement casing tests (e.g., a post-cement casing integrity test). Once the test meets specifications (e.g., until pressure at about 5000 psi is achieved for about 12-36 hours), the method continues with 673 performing a rig down drilling rig operation to remove the rig. Next, 674 fluid may be flowed through the casing tool. The fluid flow may be initiated once plugs in ports in the toe prepper dissolve after exposure to the fluid (e.g., from about 48 to 72 hours).

The method 600 continues by 675 performing rig up frac operations by installing production equipment (e.g., the Christmas tree and pumping unit of FIG. 1), 676 dropping a ball into the casing tool and seat the ball in a ball seat in the toe prepper, and 677 applying pressure to perform casing tests. The casing tests may be performed until full frac pressure is achieved. The fluid pressure 678 may be increased until the ball is released to pass through the toe prepper. The ball may be released by compressing the ball seat, moving the ball seat (e.g., downhole), dissolving a portion of the ball, etc. Once the ball is released, and 679 the wellbore may be fracked by passing the fluid under pressure through ports in the toe prepper and into the wellbore.

Part or all of the method may be performed in any order, and repeated as desired.

While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. For example, various combinations of one or more of the features and/or methods provided herein may be used.

Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter. For example, while certain tools and components (e.g., switches) are provided herein, it will be appreciated that various configurations (e.g., shape, order, orientation, etc.) of tools may be used. While the figures herein depict a specific configuration or orientation, these may vary. First and second are not intended to limit the number or order.

Insofar as the description above and the accompanying drawings disclose any additional subject matter that is not within the scope of the claim(s) herein, the inventions are not dedicated to the public and the right to file one or more applications to claim such additional invention is reserved. Although a very narrow claim may be presented herein, it should be recognized the scope of this invention is much broader than presented by the claim(s). Broader claims may be submitted in an application that claims the benefit of priority from this application.

DOWNHOLE CASING TOOL WITH INTEGRATED TOE PREPPER AND METHOD OF USING SAME

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CROSS-REFERENCE TO RELATED APPLICATIONS

Provisional Applications (1)