INTEGRATED SUB SYSTEM FOR ENHANCED OILFIELD OPERATIONS

BACKGROUND

In the petroleum industry, wells are drilled into the surface of the Earth to access and produce hydrocarbons. The process of building a well is often split into two parts: drilling and completion. Drilling a well may include using a drilling rig to drill a hole into the ground, trip in at least one string of casing, and cement the casing string in place. The casing string is used to define the structure of the well, provide support for the wellbore walls, and prevent unwanted fluid from being produced. The casing string is cemented in place to prevent formation fluids from exiting the formation and provide further structure for the well.

After a casing string has been placed in the well, the annulus located between the casing string and the wellbore wall must be cemented completely (i.e., to the surface) or partially. This is done by pumping cement from the surface, through the inside of the casing string, and up the outside of the casing string (i.e., the annulus) to the required height. Oftentimes, the slurry of cement is followed by another type of fluid and/or a wiper plug to push the remainder of the cement out of the inside of the casing and into the annulus, leaving a small amount of cement inside of the casing string. The cement is left to harden before the next section of the well is drilled or the well is completed.

SUMMARY

In one aspect, one or more embodiments of the present invention relate to an integrated sub system for isolating formations above a targeted reservoir in a well, the integrated sub system comprising: a float shoe comprising a first float valve, the first float valve being configured to regulate a flow of a fluid in a single direction; a ball seat configured to receive a ball, the ball seat comprising an aperture configured to permit the fluid through the ball seat prior to the ball seat receiving the ball; a tubular body configured to house the float shoe and the ball seat; and a circulation valve configured to be actuated hydraulically.

In one aspect, one or more embodiments of the present invention relate to method for isolating formations above a targeted reservoir in a well, the method comprising: pumping a fluid through a tubular body of an integrated sub system; permitting the fluid through an aperture of a ball seat of the integrated sub system prior to the ball seat receiving a ball; regulating, by a first float valve of a float shoe of the integrated sub system, a flow of the fluid through the body; receiving the ball within the ball seat, thereby preventing the fluid from passing through the aperture; actuating a circulation valve of the integrated sub system hydraulically; pumping cement through the body of the integrated sub system; and drilling out, by a drill bit attached to a drill pipe, the float shoe and the first float valve of the integrated sub system.

Other aspects of the present invention will be apparent from the following description and claims.

BRIEF DESCRIPTION OF DRAWINGS

Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility.

FIG. 1 shows a cross-sectional view of a conventional off-bottom cementing system in accordance with one or more embodiments of the present disclosure.

FIG. 2 shows a cross-sectional view of an integrated sub system in accordance with one or more embodiments of the present disclosure.

FIG. 3 shows a cross-sectional view of a well incorporating an integrated sub system in accordance with one or more embodiments of the present disclosure.

FIGS. 4A-4F show an operational sequence of an integrated sub system in accordance with one or more embodiments of the present disclosure.

FIG. 5 shows a flowchart of a method in accordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

Specific embodiments of the disclosure will now be described in detail with reference to the accompanying figures. In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well known features have not been described in detail to avoid unnecessarily complicating the description.

Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not intended to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

In addition, throughout the application, the terms “upper” and “lower” may be used to describe the position of an element in a well. In this respect, the term “upper” denotes an element disposed closer to the surface of the Earth than a corresponding “lower” element when in a downhole position, while the term “lower” conversely describes an element disposed further away from the surface of the well than a corresponding “upper” element. Likewise, the term “axial” refers to an orientation substantially parallel to the well, while the term “radial” refers to an orientation orthogonal to the well.

This disclosure describes systems and methods for isolating formations above a targeted reservoir in a well. The techniques discussed in this disclosure are beneficial in reducing the time required to drill out float equipment subsequent to a cementing operation, thereby reducing additional rig time and associated costs. In addition, the techniques discussed in this disclosure are beneficial in mitigating the risk associated with packing-off float equipment.

FIG. 1 shows an exemplary well 100 in accordance with one or more embodiments. The well 100 includes a wellbore 102. The wellbore 102 is a hole, drilled into the surface of the Earth, delineated by underground rock formations. The underground rock formations may or may not be filled with hydrocarbons. The wellbore 102 extends to a surface location 104. The surface location 104 is any location located along or above the surface of the Earth.

Subsequent to the wellbore 102 being drilled, a casing string is generally run into the well 100 to a planned target depth. A casing string is made of a plurality of joints of casing connected together. The target depth is usually near the deepest-most point within the Earth that the wellbore 102 reaches or the “bottom” 106 of the wellbore 102. That is, the target depth may be anywhere from 3-10 feet off of the bottom 106 of the drilled wellbore 102. However, there are multiple scenarios that prevent the casing string from being run to the target depth. These scenarios include running into an obstacle while running in-hole, drilling past the planned target depth, missing the planned target depth due to formation uncertainties, etc. When a casing string cannot be run to the target depth (e.g., bottom 106), the casing string is considered to be “off-bottom” (i.e., the deepest point of the casing string is greater than 10 feet away from the bottom 106 of the wellbore 102). In this scenario, the casing string must still be cemented in place as normal. As such, a conventional off-bottom cementing system is depicted by FIG. 1.

In one or more embodiments, the well 100 may include a plurality of casing strings. In the non-limiting example of FIG. 1, the conventional off-bottom cementing system includes a first casing string 108 and a second casing string 110. The first casing string 108 has been run in-hole and cemented in place prior to the wellbore 102 being extended. Each joint of the first casing string 108 is a tubular made of a durable material, such as steel. The casing joints may also be made of a lighter material, such as fiberglass. The wellbore 102 is extended by drilling out casing shoe accessories of the first casing string 108 and drilling a new hole into the rock formations. After the wellbore 102 has been extended, the second casing string 110 is run into the well 100 and set off-bottom as shown in FIG. 1.

The second casing string 110 is a tubular made of a material that can withstand downhole temperatures and pressures, such as steel. The second casing string 110 has an annulus 112 located between the outer surface of the second casing string 110 and the inner surface of the wellbore 102. The annulus 112 is also located between the outer surface of the second casing string 110 and the inner surface of the first casing string 108. The end of the second casing string 110 closest to the bottom 106 of the wellbore 102 is the distal end of the second casing string 110.

The second casing string 110 includes a float shoe 114 and a float collar 116. The float shoe 114 is attached to the distal end of the second casing string 110. The float shoe 114 may have a rounded profile that helps the second casing string 110 be tripped into the wellbore 102 without getting hung up on rock ledges and washouts. The float shoe 114 may include a float valve 118 located in the interior thereof.

The float valve 118 is a check valve that only allows a fluid stream in one direction. In terms of the second casing string 110 and the wellbore 102, the float valve 118 only allows the fluid stream from the inside of the second casing string 110 to the wellbore 102 and to the annulus 112. That is, the float valve 118 prevents reverse flow of fluid or U-tubing of fluid from entering the inside of the second casing string 110. The float shoe 114 may also include profiles for wiper plugs to seat in when performing a one or two plug cementing operation. The outer portion of the float shoe 114 may be made of a durable material, such as steel, and may match the size of the second casing string 110. The inner components of the float shoe 114, including the float valve 118, are made of a drillable material, such as cement or thermoplastic, because this material must be drilled out if the wellbore 102 is to be deepened beyond the second casing string 110.

The float collar 116 is also located along the distal end of the casing string at a shallower depth than the float shoe 114 (i.e., the float collar 116 is closer to the surface location 104 than the float shoe 114). The float collar 116 may also have profiles for wiper plugs to seat in, and the float collar 116 may be made of the same materials as the float shoe 114.

Typically, the second casing string 110 is made with both a float shoe 114 and a float collar 116, and both the float shoe 114 and the float collar 116 have float valves 118. This is a redundancy in case one of the float valves 118 fails. However, the second casing string 110 may be made of only a single float shoe 114 or a float collar 116 and there may be only one float valve 118 without departing from the scope of this disclosure.

The space between the distal end of the second casing string 110 and the bottom 106 of the wellbore 102 is called the open hole 120. The open hole 120 is generally at least 50 feet long when the second casing string 110 has been set off-bottom. When the second casing string 110 is cemented, cement 122 is pumped through the inside of the second casing string 110 and into the open hole 120. The open hole 120 must fill completely up with cement 122 before the cement 122 begins to fill the annulus 112.

Cementing an off-bottom casing string requires a much larger volume of cement 122 than would be required if the second casing string 110 had been set at the bottom 106 of the wellbore 102. Further, the entirety of the open hole 120 filled with hardened cement 122 must be drilled out before the wellbore 102 can be deepened and/or put on production. Therefore, systems and methods that allow a casing string, which has been set off-bottom, to be cemented without having to completely fill up the open hole 120 are beneficial.

Further, in some instances, in addition to the float shoe 114 and the float collar 116, an off-bottom casing string may include a ball seat sub (not shown), a pup joint (not shown), and full joints (not shown). This combination of components (i.e., the float shoe 114, the float collar 116, the ball seat sub, the pup joint, and the full joints) is sometimes referred to as a shoe track. It is common for a shoe track to have a length of approximately 90 feet. Because the components of the off-bottom casing string must be drilled out if the wellbore 102 is to be deepened beyond the off-bottom casing string, the shoe track must be drilled out. As such, this may be a time-consuming process due to the length of a shoe track. Therefore, systems and methods that require drilling shorter distances and/or less material are beneficial.

Embodiments disclosed herein present systems and methods that may be put in place to allow an off-bottom casing string or liner to be cemented at any depth regardless of the bottom 106 of the wellbore 102. Further, the embodiments disclosed herein present systems and methods that require drilling shorter distances and less material than the current processes of the industry that employ typical shoe tracks.

FIG. 2 shows cross-sectional view of an integrated sub system 124 for isolating formations above a targeted reservoir in a well 100 by cementing a tubular. Components shown in FIG. 2 that are the same or similar to components shown in FIG. 1 have not been redescribed for purposes of readability and have the same description and function as described above. The tubular to be cemented may be a casing string (e.g., the second casing string 110 of FIG. 1), a liner, or any tubular that has been set off-bottom.

The integrated sub system 124 includes a tubular body 126, a float shoe 114, a ball seat 128, and a circulation valve 130. In one or more embodiments, the integrated sub system 124 further includes one or more packers 132, one or more slips 134, float collar 116, and/or a plug seat 136. The body 126 is formed of a material that can withstand downhole temperatures and pressures, such as steel, and is configured to house the other elements of the integrated sub system 124. In one or more embodiments, the body 126 may be embodied as a sub. Further, in one or more embodiments, a length of the body may be equal to or less than 16 feet. An uphole end of the body 126 may connect to a liner or casing string of a well 100, such as the second casing string 110 depicted in FIG. 1. The uphole end of the body 126 may be connected to the liner or the casing string by any means known in the art, such as a threaded connection 138.

The float shoe 114 of the integrated sub system 124 is fixed and formed within a downhole end of the body 126. The float shoe 114 includes a first float valve 140 located in the interior thereof. The first float valve 140 may be a flapper type valve, a plunger type valve, or any other type of float valve known in the art. The first float valve 140 blocks a flow of a fluid (e.g., FIG. 4A) in a first direction, the direction from the downhole end to the uphole end of the integrated sub system 124, and permits the flow of the fluid in a second direction, the direction from the uphole end to the downhole end of the integrated sub system 124. The float shoe 114 and the first float valve 140 are formed of drillable materials.

The ball seat 128 of the integrated sub system 124 is fixed and formed within the body 126 uphole of the float shoe 114. The ball seat 128 may be formed of a similar, drillable material as the float shoe 114, and includes an aperture. The aperture is designed to receive a ball (e.g., FIG. 4B) dropped from the surface location 104 or uphole within the well 100. In one or more embodiments, the aperture may be concaved within the ball seat 128 having a larger diameter along the uphole end of the ball seat 128 and a smaller diameter along the downhole end of the ball seat 128. To this end, the ball has a diameter greater than the smaller diameter of the ball seat 128. Prior to receiving the ball, the fluid is permitted to pass through the aperture of the ball seat 128. However, subsequent to receiving the ball, the ball blocks the flow of the fluid from passing through the aperture of the ball seat 128, and thus, the fluid cannot pass the ball seat 128 within the body 126 of the integrated sub.

In one or more embodiments, the ball has a diameter of 1.25 inches and may be formed of phenolic, Nytef polymer, or an equivalent material. In addition, in one or more embodiments, the ball may be sized to be able to fit through a float collar 116 or a plug seat 136 of the integrated sub system 124 disposed uphole of the ball seat 128, yet not pass through the ball seat 128.

The circulation valve 130 of the integrated sub system 124 is disposed along the body 126 uphole from the ball seat 128. In one or more embodiments, the circulation valve 130 may be any form of a pressure control valve known in the art. The circulation valve 130 has an open position and a closed position. In the open position, fluid communication is permitted between the wellbore 102 and an interior of the body 126 through the circulation valve 130. In the closed position, there is no fluid communication between the wellbore 102 and the interior of the body 126 through the circulation valve 130. The circulation valve 130 may be actuated between the closed position and the open position hydraulically. In one or more embodiments, the integrated sub system 124 may include a plurality of circulation valves 130. In one or more embodiments the plurality of circulation valves 130 may be disposed and evenly spaced along a common circumference of the body 126.

In one or more embodiments, the integrated sub system 124 includes one or more packers 132 and/or one or more slips 134 disposed along the exterior of the body 126. In one or more embodiments, the packer(s) 132 and the slip(s) 134 are disposed uphole from the ball seat 128. Further, in one or more embodiments, the packer(s) 132 and the slip(s) 134 are disposed downhole from the plug seat 136. The packer(s) 132 and/or the slip(s) 134 are employed to isolate and anchor the integrated sub system 124 in place, respectively, within the wellbore 102. In one or more embodiments, the packer(s) 132 and the slip(s) 134 are hydraulically actuated. As such, the packer(s) 132 and the slip(s) 134 may be in hydraulic communication with the interior of the body 126.

The packer(s) 132 may be any packer known in the art such as a mechanical packer. Upon setting (i.e., actuation), the packer(s) 132 form a seal within the annular space between the body 126 of integrated sub system 124 and the wellbore 102. In this way, the fluid is prevented from migrating around the integrated sub system 124 in the wellbore 102 subsequent to the packer(s) 132 being set. The slip(s) 134 may be a set of tapered elements that are forced outwardly from the exterior of the body 126 against a wall of the wellbore 102. When the slip(s) 134 are pressed against the wall of the wellbore 102, the tapered elements provide upward and downward forces upon the body 126 of the integrated sub system 124, thereby fixing the position of the body 126 within the wellbore 102. That is, once set, the slip(s) 134 prevent the body 126 from rotating or moving laterally and/or axially within the wellbore 102. Although the slips 134 illustrated in FIG. 2 are shown as generally triangular elements, one of ordinary skill in the art will appreciate that the size, shape, and configuration of the slip(s) 134 are not so limited and that any slip known in the art may be used in combination with the integrated sub system 124 disclosed herein.

In one or more embodiments, the integrated sub system 124 further includes a float collar 116. The float collar 116 is fixed and formed within the body 126 uphole from the float shoe 114. In one or more embodiments, the float collar 116 is disposed downhole of the ball seat 128. Further, in one or more embodiments, the float collar 116 may also have a profile to receive the ball, thereby replacing the ball seat 128. In addition, the float collar 116 includes a second float valve 142. In this way, the integrated sub system 124 may include a first float valve 140 within the float shoe 114 and a second float valve 142 within the float collar 116 in case one of the first float valve 140 or the second float valve 142 fails. Moreover, the float collar 116 may be made of similar, drillable materials as the float shoe 114.

In one or more embodiments, the integrated sub system 124 further includes a plug seat 136. The plug seat 136 may be incorporated within a float collar 116 or a landing collar 144. In FIG. 2, the integrated sub system 124 includes a landing collar 144 having a plug seat 136. The landing collar 144 is fixed and formed within the body 126 above the circulation valve 130 and formed of a drillable material. The plug seat 136 includes an aperture designed to receive a plug (e.g., FIG. 4D) lowered in the well 100. Prior to receiving the plug, the fluid is permitted to flow through the landing collar 144 or the float collar 116 containing the plug seat 136 through the plug seat 136.

In one or more embodiments, the plug is lowered from the surface location 104 into the casing string and the attached integrated sub system 124 while following cement 122 pumped in-hole. The plug is lowered in the well 100 by an additional fluid (e.g., FIG. 4D) being pumped into the casing string on top of the plug. In this way, the plug creates a barrier between the cement 122 and the additional fluid in order to prevent intermixing between the cement 122 and the additional fluid. Besides eliminating the risk of contamination, the plug may be used to indicate proper displacement of cement 122 inside the casing string and the integrated sub system 124.

The plug is lowered within the well 100 until it reaches the plug seat 136 of the landing collar 144 or the float collar 116. Accordingly, subsequent to the plug seat 136 receiving the plug, the additional fluid is prevented from passing through the plug seat 136. Thus, the additional fluid is restricted from passing through the landing collar 144 containing the plug seat 136 by the plug. The plug is made of a drillable material, such as thermoplastic or rubber. The structure of the plug is further described in FIG. 4D.

FIG. 3 depicts a well 100 incorporating an integrated sub system 124 in accordance with one or more embodiments of the present disclosure. Components of FIG. 3 that are the same as or similar to components depicted in FIGS. 1 and 2 have not been redescribed for purposes of readability and have the same functions as described above.

Specifically, FIG. 3 shows the well 100, as depicted in FIG. 1, including the integrated sub system 124, as depicted in FIG. 2. The integrated sub system 124 is integrated within the well 100 in place of a conventional shoe track. That is, rather than the second casing string 110 including a float shoe 114, a float collar 116, a ball seat sub (not shown), a pup joint (not shown), and/or full joints (not shown), an integrated sub system 124 is connected to the second casing string 110.

In one or more embodiments, a threaded connection 138 disposed at the uphole end of the integrated sub system 124 is connected to a complementary threaded connection 146 disposed at the distal end of the second casing string 110. As such, merely a single connection between the second casing string 110 and the integrated sub system 124 is required to isolate formations above a targeted reservoir in a well 100. That is, in one or more embodiments, a threaded connection 138 disposed at an uphole end of the body 126 is employed to connect the integrated sub system 124 to a casing string or liner.

In one or more embodiments, in order to reduce the number of connections within the integrated sub system 124, the components of the integrated sub system 124 disposed within the interior of the body 126 (i.e., the float shoe 114, the float collar 116, the ball seat 128, the landing collar 144, etc.) may be integrally formed with the body 126 during the manufacturing of the integrated sub system 124. Further, in one or more embodiments, the components of the integrated sub system 124 disposed within the interior of the body 126 may be connected to the interior of the body 126 by welding, brazing, or any other connection means known in the art.

Conversely, in conventional wells 100 with shoe tracks formed of a float shoe 114, a float collar 116, a ball seat sub, a pup joint, and/or full joints, multiple sequential connections are required. For example, a first connection may be made between the second casing string 110 and a first component of the shoe track, as well as subsequent connections between each other component of the shoe track. Consequently, the multiple connections of a shoe track increase the chances of packing-off incidents within the well 100. As such, embodiments of the present disclosure disclosed herein present systems and methods which utilize only a single connection between the second casing string 110 and the integrated sub system 124, and thus, advantageously reduce the likelihood of packing-off incidents in the well 100.

FIGS. 4A-4F show an operational sequence of the integrated sub system 124 in accordance with one or more embodiments of the present disclosure. Specifically, FIGS. 4A-4F show an assembly comprising the integrated sub system 124 and the second casing string 110 of FIG. 3 set off-bottom within a wellbore 102 undergoing a cementing operation. Components of FIGS. 4A-4F that are the same as or similar to components depicted in FIGS. 1-3 have not been redescribed for purposes of readability and have the same functions as those described above.

Initially, the circulation valve 130 of the integrated sub system 124 is in the closed position and the ball seat 128 is without a ball (e.g., FIG. 4B). That is, the circulation valve 130 is in the closed position and the ball seat 128 is without the ball while the integrated sub system 124 and the second casing string 110 are run and set within the wellbore 102, as depicted in FIG. 4A. In one or more embodiments, a fluid 148 may be pumped from the surface location 104 into the second casing string 110 and the integrated sub system 124 while the assembly is run and set within the wellbore 102. In particular, because the first float valve 140 and the second float valve 142 prevent the fluid 148 already disposed within the wellbore 102 from entering the integrated sub system 124 through the downhole end of the body 126, the fluid 148 may be pumped into the assembly in order for the assembly to overcome the buoyancy force required to lower the assembly to the setting depth within the wellbore 102.

The fluid 148 pumped into the second casing string 110 from the surface location 104 enters the uphole end of the body 126 upon reaching the integrated sub system 124 and travels downhole through the body 126. Because the circulation valve 130 of the integrated sub system 124 is in the closed position and the ball seat 128 is without a ball at this time, the fluid 148 cannot exit the body 126 through the circulation valve 130 and must travel downhole through the aperture of the ball seat 128.

Subsequently, the fluid 148 passes through the second flow valve of the float collar 116 and the first float valve 140 of the float shoe 114 before exiting the integrated sub system 124 through the downhole end of the body 126. Upon exiting the integrated sub system 124, the fluid 148 enters the wellbore 102 and subsequently travels uphole in the annulus 112 to the surface location 104 as more fluid 148 is pumped through the assembly. The fluid 148 dispose within the wellbore 102 is prevented by the first float valve 140 and the second float valve 142 from reentering the integrated sub system 124 through the downhole end of the body 126.

In FIG. 4B, a ball 150 is lowered into the second casing string 110 from the surface location 104 or from within the well 100. As such, gravity and/or the pumped fluid 148 forces the ball 150 downhole through second casing string 110 and into the integrated sub system 124. In one or more embodiments, the integrated sub system 124 includes a landing collar 144, and thus, the diameter of the ball 150 must be less than the smallest diameter of the aperture of the plug seat 136 of the landing collar 144 in order for the ball 150 to pass through landing collar 144 while traveling through the integrated sub system 124. Subsequent to passing through the plug seat 136, the ball seat 128 receives the ball 150, as depicted in FIG. 4B.

Once the ball 150 is received in the ball seat 128, the fluid 148 pumped in-hole is prevented from passing through the ball seat 128. Consequently, as more fluid 148 is pumped in-hole, pressure builds up within the second casing string 110, and thus, the body 126 of the integrated sub system 124 uphole of the ball seat 128. The fluid 148 is pumped in-hole until a first predetermined pressure is reached within the integrated sub uphole of the ball seat 128.

Once the first predetermined pressure is reached, the one or more packers 132 and/or the one or more slips 134 are actuated. That is, the packer(s) 132 and/or the slip(s) 134 are hydraulically actuated by the pressure within the integrated sub system 124 uphole of the ball seat 128 upon the first predetermined pressure being reached. As a result, the packer(s) 132 and/or the slip(s) 134 extend radially from the exterior of the body 126 of the integrated sub system 124 to a wall of the wellbore 102 in order to engage the wellbore 102, as depicted in FIG. 4B. Upon engagement with the wall of the wellbore 102, the packer(s) 132 and the slip(s) 134 seal the space between the body 126 and the wall of the wellbore 102 and anchor the integrated sub system 124 within wellbore 102, respectively.

In FIG. 4C, the pumping of the fluid 148 into the second casing string 110 continues. The pressure within the second casing string 110 and the integrated sub system 124 uphole of the ball seat 128 continues to increase. The pressure continues to build until a second predetermined pressure is reached. Consequently, the circulation valve 130 is hydraulically actuated subsequent to the second predetermined pressure being reached. Specifically, upon actuation, the circulation valve 130 transitions from a closed position to an open position. As such, fluid communication is established between the body 126 of the integrated sub system 124 uphole of the ball seat 128 and the portion of the wellbore 102 uphole of the packer(s) 132 through the circulation valve 130. In this way, the fluid 148 previously disposed within the integrated sub system 124 uphole of the ball seat 128 exits the integrated sub system 124 through the circulation valve 130 and enters the wellbore 102.

Upon exiting the integrated sub system 124, the fluid 148 is prevented by the previously actuated packer(s) 132 from traveling downhole in the wellbore 102 past the packer(s) 132. As such, the fluid 148 travels uphole to the surface location 104 through the annulus 112 as more fluid 148 is pumped through the assembly.

In one or more embodiments, the fluid 148 pumped in-hole during the operational sequence of FIGS. 4A-4C may be a spacer fluid. The spacer fluid may be any fluid having properties that will not react to properties of cement 122. The cement 122 is a fluid designed to harden, or set, after a period of time.

In FIG. 4D, the fluid 148 is followed by the cement 122. That is, the cement 122 is pumped from the surface location 104 in-hole into the assembly of the second casing string 110 and the integrated sub system 124. In addition, a plug 152 is pumped from the surface location 104 into the assembly following the cement 122. The plug 152 is made of a drillable material, such as thermoplastic or rubber.

In one or more embodiments, the plug 152 is made of a core and collapsible fins that are disposed around the core. In the non-limiting example of FIG. 4D, the core of the plug 152 is hollow. However, in one or more embodiments, the core may be solid. The fins, in their expanded state, fit flush within the inside of the second casing string 110. In addition, in one or more embodiments, the fins may fit flush within the body 126 of the integrated sub system 124 in their expanded state. Alternatively, in one or more embodiments, the fins may collapse to a size such that the plug 152 fits flush within the body 126.

The plug 152 is followed by an additional fluid 154 such as a completion fluid. The completion fluid may be any fluid that is designed to be left in the workover well 100 for a period of time such as water mixed with corrosion inhibitor. In one or more embodiments, the additional fluid 154 may be a fluid, like a drilling mud, that may be used to drill out the integrated sub system 124 to extend the wellbore 102 or put the well 100 back on production. Further, in one or more embodiments, the additional fluid 154 may be the same as the fluid 148.

The plug 152 creates a barrier between the cement 122 and the additional fluid 154, thereby preventing the cement 122 and the additional fluid 154 from mixing. Further, in one or more embodiments, as the plug 152 is lowered within the assembly, the plug 152 wipes cement residual from the inside of the second casing string 110 and the inside of the body 126 uphole of the plug seat 136.

In FIG. 4D, the additional fluid 154 is being pumped from the surface location 104 and following the plug 152, the cement 122, and the fluid 148 that have previously been pumped from the surface location 104. As the additional fluid 154 is pumped into the assembly of the second casing string 110 and the integrated sub system 124, the additional fluid 154, and thus, the plug 152, displace the cement 122 within the well 100. Specifically, because the ball 150 disposed within the ball seat 128 is preventing fluid from passing the ball seat 128 and the circulation valve 130 is in the open position, the cement 122 is forced out of the circulation valve 130 into the annulus 112 of the well 100.

In FIG. 4E, the plug 152 has been pumped to the plug seat 136 of the integrated sub system 124. Accordingly, the plug 152 and the aperture of the plug seat 136 are sized such that the plug 152 is prevented from passing through the plug seat 136.

The volumes of fluid (i.e., the fluid 148, the cement 122, and the additional fluid 154) pumped into the well 100 during the cementing operation are calculated such that by the time the plug 152 is received within the plug seat 136, the cement 122 has reached the surface location 104 or a designated setting height within the annulus 112. In one or more embodiments, some cement 122 may be left within the body 126 of the integrated sub system 124 uphole of the ball seat 128 subsequent to the plug seat 136 receiving the plug 152, as depicted in FIG. 4E.

In addition, in one or more embodiments, subsequent to the plug seat 136 receiving the plug 152, the pressure within the body 126 of the integrated sub system 124 between the plug seat 136 and the ball seat 128 may drop below a third predetermined pressure. That is, in one or more embodiments, the plug 152 may prevent the additional fluid 154 from passing through the plug seat 136 subsequent to the plug seat 136 receiving the plug 152. To this end, the pressure within the body 126 between the plug seat 136 and the ball seat 128 reduces since no additional fluid 154 can be pumped past the plug seat 136 and the circulation valve 130 is still currently in the open position. As such, the circulation valve 130 may return to the closed position once the pressure within the body 126 between the plug seat 136 and the ball seat 128 falls below the third predetermined pressure. In one or more embodiments, the third predetermined pressure may be equal to the second predetermined pressure or the first predetermined pressure.

After the circulation valve 130 returns to the closed position, fluid communication between the integrated sub system 124 and the annulus 112 above the packer(s) 132 is lost. In this way, the cement 122 within the annulus 112 of the wellbore 102 above the packer(s) 132 is prevented from reentering the integrated sub system 124.

While the integrated sub system 124 depicted in FIGS. 4A-4F show a singular plug system being utilized, a conventional dual plug system (not shown) may be used without departing from the scope of this disclosure herein. That is, in one or more embodiments, a conventional dual plug system may be employed in order to further prevent the cement 122 from mixing with the fluid 148 pumped into the well 100 prior to the cement 122. As is well known in the art, when fluid and cement 122 mix, the cement 122 job may be compromised, because the cement 122 may no longer have the required values of certain cement 122 parameters, such as setting time or compressive strength. Accordingly, in one or more embodiments, the integrated sub system 124 may include a bottom plug seat (not shown) to receive a bottom plug (not shown) that is designed to create a barrier between the fluid 148 pumped in the well 100 prior to the cement 122, and a top plug seat (not shown) to receive a top plug (not shown) that is designed to create a barrier between the cement 122 and the additional fluid 154 pumped into the well 100 after the cement 122. Alternatively, in one or more embodiments, the plug seat 136 may house both the bottom plug and top plug. In any case, the bottom plug may be further designed to scrape off any residue or mud film that may be on the inner surface of the second casing string 110 prior to the cement 122 contacting this residue or film.

In FIG. 4F, the components disposed within the interior of the body 126 of the integrated sub system 124 (i.e., the landing collar 144, the ball seat 128, the float collar 116, and the float shoe 114) and any cement 122 left within the body 126 are drilled out while the integrated sub system 124 is anchored by the slip(s) 134. In particular, in one or more embodiments, a drill bit 156 attached to a drill pipe 158 is lowered within the well 100 through the second casing string 110 in order to drill out the interior components of the integrated sub system 124. In one or more embodiments, the integrated sub system 124 may be drilled out subsequent to the cement 122 within the annulus 112 hardening such that the set cement 122 acts as an additional anchoring means for the integrated sub system 124 within the wellbore 102 during the drilling process.

FIG. 5 depicts a flowchart 500 showing a method for isolating formations above a targeted reservoir in a well 100. While the various flowchart blocks in FIG. 5 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the blocks may be executed in different orders, may be combined or omitted, and some or all of the blocks may be executed in parallel. Furthermore, the blocks may be performed actively or passively.

In step 501, an uphole end of a body 126 of an integrated sub system 124 is attached to a downhole end of a casing string or a liner. Accordingly, in one or more embodiments, a threaded connection 138 is of the body 126 is connected to a complementary threaded connection 146 of the casing string or liner prior to the integrated sub system 124 and the connected casing string or liner being run into a well 100. Once connected, the integrated sub system 124 and the casing string or liner are run into the well 100 to a desired depth and set off-bottom. In one or more embodiments, a fluid 148 is pumped from the surface location 104 into the casing string or liner and the body 126 of the connected integrated sub system 124 while the integrated sub system 124 and the casing or liner are run into the well 100.

In step 502, the integrated sub system 124 and the casing string or liner are set off-bottom in the well 100, and the fluid 148 is continued to be pumped from the surface location 104 into the into the body 126 of the integrated sub system 124. The fluid 148 passing through the body 126 is permitted to flow through a ball seat 128 of the integrated sub system 124 disposed within the body 126. That is, prior to the ball seat 128 receiving a corresponding ball 150, the fluid 148 may pass through ball seat 128 via an aperture of the ball seat 128.

In step 503, a float shoe 114 disposed along the downhole end of the body 126 regulates the fluid 148 passing through the body 126 of the integrated sub system 124. That is, by way of a first float valve 140 situated within the float shoe 114, the float shoe 114 permits the fluid 148 to flow downhole through the float shoe 114 while simultaneously preventing the fluid 148 disposed within a downhole end or open hole 120 of a wellbore 102 of the well 100 from entering the downhole end of the body 126. In this way, as the fluid 148 passes through and exits the body 126 through the float shoe 114, the fluid 148 enters the wellbore 102 and is pumped back uphole to the surface location 104 as more fluid 148 is pumped in-hole. In one or more embodiments, the integrated sub system 124 may further include a float collar 116 within the body 126 that includes a second float valve 142 as a redundancy in case the first float valve 140 of the float shoe 114 fails.

In step 504, the ball 150 is lowered within the well 100 to the integrated sub system 124 by gravity and/or the pumped fluid 148. Accordingly, the ball 150 travels through the body 126 and is received by the ball seat 128 of the integrated sub system 124. Subsequent to the ball seat 128 receiving the ball 150, the ball 150 prevents the fluid 148 from traveling through the aperture of the ball seat 128. As such, fluid communication between the portion of the body 126 uphole of the ball seat 128 and the portion of the body 126 downhole of the ball seat 128 is lost once the ball seat 128 receives the ball 150.

As a result of the fluid 148 being prevented from passing through the ball seat 128, pressure builds within the body 126 of the integrated sub system 124 uphole of the ball seat 128 as more fluid 148 is pumped into the body 126. Once a first predetermined pressure is reached within the body 126 uphole of the ball seat 128 due to the increase of pressure, one or more packers 132 and/or one or more slips 134 of the integrated sub system 124 are hydraulically actuated. Accordingly, in one or more embodiments, the packer(s) 132 extend radially from an exterior of the body 126 to a wall of the wellbore 102 in order to engage the wellbore 102, thereby sealing the space between the body 126 and the wall of the wellbore 102. Further, in one or more embodiments, the slip(s) 134 extend radially from the exterior of the body 126 to the wall of the wellbore 102 in order to engage the wellbore 102, thereby anchoring the integrated sub system 124 within wellbore 102.

In step 505, pumping of the fluid 148 in-hole is continued and the pressure within the body 126 uphole of the ball seat 128 builds further. Once the pressure reaches a second predetermined pressure, that being greater than the first predetermined pressure, the circulation valve 130 is hydraulically actuated. Upon actuation, the circulation valve 130 transitions from a closed position to an open position. With the circulation valve 130 in the now open position, fluid communication is established between the body 126 uphole of the ball seat 128 and annulus 112 of the wellbore 102 uphole of the packer(s) 132 through the circulation valve 130. Consequently, the fluid 148 previously disposed within the body 126 uphole of the ball seat 128 exits the integrated sub system 124 through the circulation valve 130 and enters the annulus 112. The packer(s) 132 engaged with the wellbore 102 prevent the fluid 148 from traveling downhole in the wellbore 102 past the packer(s) 132. Accordingly, the fluid 148 travels uphole to the surface location 104 through the annulus 112 as more fluid 148 is pumped into the uphole end of the integrated sub system 124.

In step 506, cement 122 is pumped from the surface location 104 into the well 100 and the integrated sub system 124 following the fluid 148. The cement 122 is prevented by the ball 150 within the ball seat 128 from traveling past the ball seat 128 within the body 126. As such, subsequent to the cement 122 entering the uphole end of the body 126, the cement 122 exits the body 126 through the open circulation valve 130, thereby entering the annulus 112 of the wellbore 102 uphole of the packer(s) 132. As more cement 122 is pumped into the well 100 and the integrated sub system 124, the cement 122 within the annulus 112 travels further uphole towards the surface location 104.

In one or more embodiments, once a desired amount of cement 122 has been pumped into the well 100, a plug 152 is pumped into the well 100 from the surface location 104 following the cement 122. The plug 152 may be forced downhole within the well 100 by the pumping of an additional fluid 154 from the surface location 104 following the plug 152. In one or more embodiments, the plug 152 forms a barrier between the additional fluid 154 and the cement 122, thereby preventing the additional fluid 154 and the cement 122 from mixing.

The cement 122 is further displaced into the annulus 112 through the circulation valve 130 of the integrated sub system 124 as the additional fluid 154 and the plug 152 are pumped into the well 100. The plug 152 is pumped and lowered by the additional fluid 154 until the plug 152 is received within a plug seat 136 of the integrated sub system 124.

In one or more embodiments, the plug seat 136 is formed within a landing collar 144 or a float collar 116 disposed within the body 126 uphole of the circulation valve 130. Upon the plug seat 136 receiving the plug 152, the additional fluid 154 is prevented from passing downhole of the plug seat 136 within the body 126. In one or more embodiments, the volumes of fluid (i.e., the fluid 148, the cement 122, and the additional fluid 154) pumped into the well 100 are calculated such that by the time the plug 152 is received within the plug seat 136, the cement 122 has been displaced to the surface location 104 or a designated setting height within the annulus 112. Further, in one or more embodiments, the integrated sub system 124 may include and employ a conventional dual plug system.

In addition, in one or more embodiments, the pressure within the body 126 of integrated sub system 124 between the plug seat 136 and the ball seat 128 may drop below a third predetermined pressure subsequent to the plug seat 136 receiving the plug 152. Consequently, the circulation valve 130 may return to the closed position subsequent to the pressure within the body 126 between the plug seat 136 and the ball seat 128 falling below the third predetermined pressure. As such, the cement 122 within the annulus 112 is prevented from reentering the body 126 through the circulation valve 130.

In step 507, a drill bit 156 attached to a drill pipe 158 is lowered within the well 100 through to the integrated sub system 124 in order to drill out the interior components (i.e., the landing collar 144, the ball seat 128, the float collar 116, and the float shoe 114) of the integrated sub system 124 and any cement 122 still disposed within the body 126. In one or more embodiments, the integrated sub system 124 is anchored by the slip(s) 134 during the drilling process. In one or more embodiments, the integrated sub system 124 may be drilled out subsequent to the cement 122 within the annulus 112 hardening such that the set cement 122 acts as an additional or sole anchoring means for the integrated sub system 124 within the wellbore 102 during the drilling process.

Subsequent to the drilling process, the wellbore 102 may be deepened and/or put on production. In one or more embodiments, the packer(s) 132 and/or the slip(s) 134 remain engaged with the wellbore 102 subsequent to the drilling process. In addition, subsequent to the drilling process, fluid communication may be reestablished between the surface location 104 and the open hole 120 of the wellbore 102 in both the uphole and downhole directions.

Accordingly, the aforementioned embodiments as disclosed relate to integrated sub systems 124 and methods useful for isolating formations above a targeted reservoir in a well 100. The disclosed integrated sub systems 124 and methods advantageously reduce the required time of drilling float equipment subsequent to a cementing operation due to the length of the integrated sub system 124 being significantly less than the length of a conventional shoe track. This benefit, in turn, advantageously reduces additional rig time and associated costs.

Further, the disclosed integrated sub systems 124 and methods advantageously mitigate the risk associated with packing-off float equipment as the integrated sub system 124 may be secured within the wellbore 102 by the hardened cement 122 and slip(s) 134 prior to drilling out the interior components of the integrated sub system 124. In addition, the disclosed integrated sub systems 124 and methods advantageously mitigate the risk associated with packing-off float equipment as the integrated sub system 124 utilizes only a single connection between the integrated sub system 124 and the connected casing string or liner. Thus, the disclosed integrated sub systems 124 and methods advantageously eliminate the use of a through-tubing motor to drill through the float equipment as the use of a through-tubing motor is generally employed to mitigate the risk associated with packing-off float equipment.

Although only a few embodiments of the invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke AIA 35 U.S.C. § 112 (f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

INTEGRATED SUB SYSTEM FOR ENHANCED OILFIELD OPERATIONS

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CPC

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