Patent Application
20190234187
The present disclosure relates in general to a downhole drilling and more particularly to cased bore tubular drilling systems and methods.
During well site operations, such as oil and gas exploration, various wellbore tubulars (e.g., piping components) may be lowered into a wellbore formed in a ground formation. Traditionally, these tubulars are hung or suspended from equipment at the surface via hangers having one or more load shoulders for supporting the weight of the tubulars. The hangers may be part of a surface wellhead system, offshore drilling system, or subsea system that may be costly to install and maintain at the well site. Consequently, the cost of the hanger systems may be prohibitively expensive for exploratory drilling operations. As a result, potentially recoverable reserves may not be utilized to their full potential.
Applicants recognized the problems noted above herein and conceived and developed embodiments of systems and methods, according to the present disclosure, for downhole tubular systems.
In an embodiment a system for positioning a tubular component within a wellbore includes a pair of wellbore tubulars coupled together via a casing collar, the wellbore tubulars having a longitudinal axis substantially aligned with a wellbore axis. The system also includes a hold down collar arranged circumferentially about the casing collar, the hold down collar securing the casing collar to the wellbore tubulars. The system further includes an actuating piston including an actuating body, the actuating piston being axially movable along the wellbore axis between an activated position and a deactivated position, the actuating body moving along with the actuating piston. The system also includes slip elements arranged downstream of the actuating piston, the slip elements receiving the actuating body in a space formed between the slip elements, wherein the actuating body drives the respective slip elements in opposite radial directions when in the activated position to secure the wellbore tubulars within the wellbore.
In another embodiment a system for hanging a wellbore tubular within a wellbore includes a first segment of casing tubular. The system also includes a second segment of casing tubular, the second segment coupled to the first segment via a casing collar. The system includes a hold down collar arranged circumferentially about the casing collar and securing the first segment to the second segment, the hold down collar extending radially outward from the first and second segments. The system further includes an upper nut abutting a lower shoulder formed by the casing collar and being coupled to at least one of the casing collar or the hold down collar. The system also includes an actuating piston positioned proximate of the upper nut, wherein at least a portion of the actuating piston is radially outward of the upper nut, and the actuating piston is moveable along a longitudinal axis of the wellbore relative to the upper nut. The system includes an actuating body positioned within an opening in the actuating piston, wherein the actuating body is coupled to the actuating piston such that movement of the actuating piston is transferred to the actuating body. The system also includes slip elements positioned downhole of the actuating piston, wherein movement of the actuating piston transitions the slip elements from a deactivated position to an activated position where the slip elements move radially from one another in opposite directions.
In an embodiment a method for installing a wellbore tubular in a wellbore includes coupling a first casing tubular to a second casing tubular via a casing collar. The method also includes securing the first casing tubular to the second casing tubular via a hold down collar. The method further includes securing an activation system to at least one of the casing collar or the hold down collar. The method also includes positioning the first and second casing tubulars within the wellbore. The method further includes transitioning the activation system from a deactivated position to an activated position.
The foregoing aspects, features, and advantages of the present disclosure will be further appreciated when considered with reference to the following description of embodiments and accompanying drawings. In describing the embodiments of the disclosure illustrated in the appended drawings, specific terminology will be used for the sake of clarity. However, the disclosure is not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.
The foregoing aspects, features, and advantages of the present disclosure will be further appreciated when considered with reference to the following description of embodiments and accompanying drawings. In describing the embodiments of the disclosure illustrated in the appended drawings, specific terminology will be used for the sake of clarity. However, the disclosure is not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.
When introducing elements of various embodiments of the present disclosure, the articles “a”, “an”, “the”, and “said” are intended to mean that there are one or more of the elements. The terms “comprising”, “including”, and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Any examples of operating parameters and/or environmental conditions are not exclusive of other parameters/conditions of the disclosed embodiments. Additionally, it should be understood that references to “one embodiment”, “an embodiment”, “certain embodiments”, or “other embodiments” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, reference to terms such as “above”, “below”, “upper”, “lower”, “side”, “front”, “back”, or other terms regarding orientation or direction are made with reference to the illustrated embodiments and are not intended to be limiting or exclude other orientations or directions.
Embodiments of the present disclosure include a cased bore tubular drilling and completion system (CBTDCS) for use in downhole drilling operations. In various embodiments, the CBTDCS enables one or more wellbore components to be suspended from a location within an inner diameter of a wellbore without hanging the components from surface equipment, such as a casing or tubing hanger. For example, the CBTDCS may include one or more actuatable slip elements that engage an inner diameter of the wellbore, which may be cased, and an outer diameter of a wellbore tubular, such as casing. Accordingly, components may be suspended within the wellbore with increased flexibility and reduced costs, thereby enabling additional exploratory wells and/or more wells at a given site. In various embodiments, the CBTDCS includes an actuating piston that is driven into an engaged position via a fluid pressure introduced into an annulus of the wellbore. The fluid pressure may enter a void space via a flow line coupled to a one-way valve. The valve may block the fluid from exiting the void space until a predetermined condition, such as a certain pressure condition, is reached. As a result, the CBTDCS may remain in an activated position until a certain condition is met. In various embodiments, the CBTDCS further includes a sealing element that may be compressed and loaded within the annulus of the wellbore. This seal may block fluid and/or gas from moving uphole (e.g., in an upward direction) past the CBTDCS. Upon completion of operations, the CBTDCS may be removed from the wellbore by applying a pressure exceeding the capacity of the rupture disk or similar device. This will result in the rupture disk bursting and releasing the fluid from the void space. Thereafter, the CBTDCS may be removed from the wellbore via application of an upward force.
In various embodiments, the CBTDCS may be utilized in a variety of configurations, such as with surface wellhead equipment, offshore applications, subsea completion systems, mudline suspension systems, drilling systems, and the like. The CBTDCS enables suspension of tubular strings without a fixed landing point, thereby improving flexibility of operations. Furthermore, various components associated with conventional wellhead equipment may be eliminated by utilizing the CBTDCS. In various embodiments, the CBTDCS is actuated using annular pressure, and as a result control lines and the like may not be utilized. The system further may be activated in a single operation. As will be described in detail below, pressurizing the annulus may deploy the actuating piston to activate the slip elements, which seals and grips an outer casing inner diameter to an interior casing outer diameter. The system further reduces capital expenditures due to the replacement or elimination of conventional wellhead equipment. Furthermore, the reduced number of parts may produce more efficient operations and reduced operating expenditures.
Systems and methods of the present disclosure are directed toward improved completion systems that may be utilized within the inner diameter (ID) of casing to enable suspension and deployment of wellbore tubulars at different locations along a length of a wellbore. This offers flexibility for operators and also reduces costs associated with expensive wellbore equipment, such as the equipment illustrated in
The interior casing 34 is deployed in tubular joints and coupled together via a casing collar 38. In various embodiments, the casing collar 38 may be formed in accordance with API standards, as may other equipment described herein. As shown, the casing collar 38 is not anchored against the casing 32, and rather, extends radially outward from the interior casing 34 and into the annulus 36. In other words, the casing collar 38 may not be radially flush with the interior casing 34. The casing collar 38 may provide a shoulder 40 that is utilized during deployment of various components of the CBTDCS 30, as will be described in detail below. The illustrated casing collar 38 is restrained with a hold down collar 42. In various embodiments, the hold down collar 42 is a split ring that is arranged around the casing collar 38. Additionally, in embodiments, the hold down collar 42 may be a one-piece, continuous structure that is arranged over the casing collar 38. As illustrated, the hold down collar 42 extends radially outward from the interior casing 34 and the casing collar 38 and into the annulus 36. In various embodiments, the hold down collar 42 may form at least a portion of the shoulder 40.
The illustrated CBTDCS 30 further includes an activation system 44 for hanging the interior casing 34 from the casing 32. That is, various tubular joints of the interior casing 34a, 34b may be coupled together and suspended from the casing 32 using the CBTDCS 30. The illustrated activation system 44 includes an upper nut 46 positioned downhole from the casing collar 38. In various embodiments, the upper nut 46 is arranged proximate to and in contact with the shoulder 40. In various embodiments, the upper nut 46 may be secured to at least one of the casing collar 38 or the hold down collar 42, for example, via a fastener.
In various embodiments, the upper nut 46 includes one or more passages or ports 48 to facilitate fluid flow to areas downhole of the upper nut 46. As will be described below, fluid may be transported through the annulus 36 and the upper nut 46 to activate one or more pistons to drive seal segments into the casing 32 and the interior casing 34. The ports 48 may be coupled to hydraulic lines, as will be described below, to facilitate transport of the fluid.
The illustrated upper nut 46 is arranged proximate an actuating piston 50. In various embodiments, seals 52 extend from the upper nut 46 and rest against the actuating piston 50 to block fluid flow past the actuating piston 50. Furthermore, in various embodiments, the seals 52 may facilitate movement (e.g., vertical travel) between the actuating piston 50 and the upper nut 46 by limiting or reducing the likelihood of sticking or friction between the actuating piston 50 and the upper nut 46. Arranged between the actuating piston 50 and the upper nut 46 is a void space 54, which may extend circumferentially about the CBTDCS 30. This void space 54 receives fluid that travels through the ports 48, thereby driving movement of the actuating piston 50 in a downward direction 56.
The actuating piston 50 includes a slip carrier 58 holding an actuating body 60. In various embodiments, movement of the actuating piston 50 is transmitted to the actuating body 60, via the slip carrier 58, and therefore movement of the actuating piston 50 translates to movement of the actuating body 60. The actuating body extends through a sealing element 62 arranged in the annulus 36 between the casing 32 and the interior casing 34. As will be described in detail below, when the CBTDCS 30 is activated, the sealing element 62 is compressed by a lower portion of the actuating piston 50 and a rear portion of the actuating body 60. In various embodiments, the sealing element 62 is a metal to metal sealing element. However, in embodiments, the sealing element 62 may be a metal encapsulated bulk rubber seal, an elastomer seal, an inflatable/injectable sealing element, or the like. Furthermore, while the illustrated embodiment shows a single sealing element 62, there may be two, three, four, or any reasonable number of sealing elements. As illustrated, a gap 64 is arranged between the actuating body 60 and the actuating piston 50 that enables compression of the sealing element 62 when fully energized. As a result, the actuating piston 50 may move in the downward direction 56 until the gap 64 is almost or substantially eliminated so that the actuating piston 50 bottoms out against the sealing element 62 and not the top of the actuating body 60.
The illustrated actuating body 60 is generally arrow shaped in that it has a rear end 66 having a generally rectangular shape and a head end 68 having a generally triangular shape. As shown, the head end 68 is angled on a front face 70 and on a rear face 72, the angular direction being substantially opposite. That is, an angle 74 on the rear face 72 is generally obtuse while the angle 76 on the front face 70 is generally acute. The obtuse angle 74 on the rear face 72 facilitates compression of the sealing element 62 when the actuating body 60 is driven in the downward direction 56.
The illustrated CBTDCS 30 further includes the slip elements 78. In various embodiments, the slip elements 78 include a slip ring. However, the slip elements 78 may be slip segments in embodiments. In certain embodiments, the slip elements 78 may be metallic components that include teeth 80 that bite or cut into the casing 32 and/or the interior casing 34. Upon activation by the actuating body 60, the slip elements 78 are driven apart in first and second radial directions 82 (radially outward), 84 (radially inward) and into the inner diameter of the casing 32 and the outer diameter of the interior casing 34. As a result, the interior casing 34 is coupled to the casing 32 without suspension from above, for example from a surface component such as a wellhead system. Accordingly, the illustrated CBTDCS 30 provides improved flexibility in wellbore operations because it may be deployed along any location within the wellbore 16. Furthermore, the CBTDCS 30 may be deployed in stages along the length of the wellbore 16. As a result, costs associated with wellhead equipment may be reduced while still providing the functionality associated with vertical hanging systems.
In certain embodiments, the actuating piston 50 is driven in the downward direction 56 via a fluidic force, for example, from a blow-out preventer (BOP). For instance, the BOP may be shut and pressurized fluid may be driven into the annulus 36. A valve 86 is arranged within the annulus 36 in the illustrated embodiment to direct the fluid into a flow line 88 coupled to the upper nut 46. In various embodiments, the valve 86 further includes a relief component 90, which is a rupture disk in the illustrated embodiment. In operation, the valve 86 may be a one way valve, such as a ball check valve, that enables the fluid to flow in the downward direction 56 and into the void space 54, but blocks fluid from flowing out of the valve 86. As a result, fluid pressure is maintained within the void space 54 and therefore the actuating body 60 maintains the slip elements 78 in an engaged position where the teeth 80 contact the inner diameter of the outer casing 32 and the outer diameter of the interior casing 34. To remove the CBTDCS 30, the void space 54 and the flow line 88 may be pressurized to a point that the relief component 90 releases the pressure from the void space 54. For example, in embodiments where the relief component 90 is a rupture disk, the flow line 88 may be pressurized to a predetermined pressure that will cause the rupture disk to break and relieve the fluid pressure. Thereafter, the CBTDCS 30 may be removed from the wellbore 16.
Further illustrated in
The embodiment illustrated in
In the illustrated embodiment, both the upper nut 46 and the actuating piston 50 have respective corresponding profiles 130, 132. These profiles 130, 132 enable a mating fit between the upper nut 46 and the actuating piston 50, thereby enabling entry into the wellbore 16 within the annulus 36. Furthermore, the profiles 130, 132 provide a tortuous flow path in the event that fluids leak past the seals 52. That is, fluid leaking past the seals 52 may change directions multiple times, thereby reducing pressure and decreasing the force of the fluid. The profiles 130, 132 separate at the void space 54, which enables pressurized fluid to enter and drive the actuating body 60, via a stroke of the actuating piston 50, in the downward direction 56 to engage the slip elements 78.
The illustrated actuating piston 50 receives and supports the actuating body 60 within the slip carrier 58. As shown, the actuating piston 50 includes the opening 134 for holding the actuating body 60. As will be described below, a length 136 of the opening 134 is longer than the rear end 66 of the actuating body 60, thereby enabling axial movement of the actuating body 66 within the opening 134. The actuating body 60 is secured within the opening 134 by a retainer ring 138. The retainer ring extends radially outward from the rear end 66 of the actuating body 60 and blocks axial movement in the downward direction 56 when the retainer ring 138 contacts a shoulder 140 formed within the opening 134. In the illustrated embodiment, the retainer ring 138 rests on the shoulder 140, thereby forming the gap 64 within the opening 134. As described above, the gap 64 may be reduced or be filled with the rear end 66 of the actuating body 60 when the actuating piston 50 is driven in the downward direction 56.
As described above, the actuating body 60 includes the front face 70 and the rear face 72. The rear face 70 includes a substantially angled surface at the angle 74. As shown, the shape of the rear face 70 is opposite the shape of the lower end 142. As a result, the two angled faces will drive into the sealing element 62 substantially near the center to thereby drive the sealing element 62 outward and into the interior casing 34 and the casing 32.
The slip elements 78 illustrated in
The foregoing disclosure and description of the disclosed embodiments is illustrative and explanatory of the embodiments of the invention. Various changes in the details of the illustrated embodiments can be made within the scope of the appended claims without departing from the true spirit of the disclosure. The embodiments of the present disclosure should only be limited by the following claims and their legal equivalents.
