Patent Application
20230235641
Cementing operations are an integral part of drilling wells in the oil and gas industry. Cementing operations may be performed to install casing in a well, where cement may be pumped in the well between the casing and the wellbore wall. For example, as shown in
Precautions may be taken during cementing operations to determine optimal pumping pressures for each well section. Determining an optimal cement pumping pressure requires compromise between an upper limit based on surrounding formation fracture pressure and a lower limit based on a minimum pumping pressure to ensure complete and proper cement distribution. For example, in considering the upper limit, excessive pumping pressure (e.g., greater than the fracture pressure of the surrounding formation) may create fractures in a surrounding formation, which may lead to fluid losses through the generated cracks. When considering the lower limit, the pressure and corresponding flow rate of the cement must be high enough to ensure sufficient displacement of cement across the entire well before cement thickening. In many cases, high cement pump rate is preferred, particularly in formations where high fracture pressures are present and in casing cementing operations. High cement pump rates can reduce the overall duration of cementing operations, reduce costs, and, in some cases, improve quality of cementing operations due to better cement mixing and distribution around the casing.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In one aspect, embodiments disclosed herein relate to a pipe section. The pipe section may include a tubular body having a wall defining an interior flow path extending axially through the tubular body and a turbine assembly assembled to a first portion of the wall. The turbine assembly may include a link rod extending through the wall, from an interior of the tubular body to an exterior of the tubular body, an inner turbine mounted on the link rod in the interior of the tubular body, wherein the inner turbine is rotatable about the link rod, and an outer impeller mounted on the link rod at the exterior of the tubular body, wherein the outer impeller is rotatable about the link rod. The pipe section may further include a protective shield disposed around the outer impeller.
In another aspect, embodiments disclosed herein relate to a system which may include a casing disposed in a wellbore within a well, where an annulus may be created between the casing and the wellbore, and a mixing pipe section may be coaxially connected to the casing. The mixing pipe section may include a turbine assembly assembled to a wall of the mixing pipe section. The turbine assembly may include a link rod extending through the wall, from an interior of the mixing pipe section to an exterior of the mixing pipe section, an inner turbine mounted on the link rod in the interior of the mixing pipe section, wherein the inner turbine is rotatable about the link rod, and an outer impeller mounted on the link rod at the exterior of the mixing pipe section, such that the outer impeller is disposed in the annulus, wherein the outer impeller is rotatable about the link rod.
In yet another aspect, embodiments disclosed herein relate to a method, which may include providing a string of pipe extending through a well. The string of pipe may include a plurality of pipe sections threadably connected in an end-to-end fashion, a mixing pipe section threadably connected to the plurality of pipe sections, an interior flow path extending axially through the string of pipe, and an exterior annular space extending axially along an exterior of the string of pipe. The mixing pipe section may include a link rod extending through a wall of the mixing pipe section, an inner turbine mounted on the link rod and interfacing with the interior flow path in the mixing pipe section, and an outer impeller mounted on the link rod in the exterior annular space around the mixing pipe section. The method may further include pumping a first fluid through the interior flow path to hydraulically rotate the inner turbine and using hydraulic rotation of the inner turbine to drive rotation of the outer impeller via the link rod connecting the inner turbine and the outer impeller.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
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 size 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. Further, the particular shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the particular elements and have been solely selected for ease of recognition in the drawing.
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 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.
Throughout the application the reference to tubing may refer to a string of casing defined as a large-diameter pipe that may be lowered into a well and connected to the surface of the Earth, to a string of casing (or liner) that may be lowered into a well and connected to an end of a previously installed casing, to a string of production tubing defined as a large-diameter pipe that may be lowered into a well and through which production fluids flow, or other downhole tubing.
In one aspect, embodiments disclosed herein relate to improving the efficiency and quality of cementing operations via the implementation of a hydraulic mixing apparatus to enhance cement mixing and cement distribution around a downhole tubing. Further, in another aspect, embodiments disclosed herein relate to transferring kinetic energy from a fluid in an interior flow path of a tubing to a fluid in an exterior annular space around the tubing via an energy transfer assembly incorporated into a section of the tubing within a wellbore.
Cementing operations often include consideration of many different factors, such as cement pumping pressure, fracturing pressure of a surrounding formation, rheology and composition of the cement, and thickening time of the cement. For example, high pumping pressure of a cement through a formation with relatively low fracturing pressure may result in fracturing of the formation, and fluid losses through the induced cracks. Additionally, due to the relatively high density of cement (e.g., compared with drilling fluids), the relatively higher hydrostatic pressure of a cement column may result in a higher bottom hole pressure (BHP) while pumping the cement, which can induce formation fractures and losses. As a result, many precautions may be taken during cementing operations to determine optimal pumping pressures and/or flow rates for each section of a well being cemented to avoid losses, while also pumping at a high enough rate to displace cement across the entire well section before the cement thickens.
There are some cases in which a high cement pump rate is favored. For example, in formations with high fracture pressure or in situations where cement is being pumped inside casing, a high cement pump rate may be preferable. In these cases, increasing cement flow rate may not induce losses despite a higher BHP. In some instances, higher pumping rates can allow for better drilling fluid removal if turbulent flow is achieved around the annulus, resulting in better cement quality and prevention of cement contamination. However, due to excessive vibrations and limited pumping capacity in current cement pumping units, achieving higher pump rates may be difficult. By using devices according to embodiments of the present disclosure provided along a tubing string being cemented, an improved cementing operation may be achieved using a standard pumping rate of a fluid flowing through the tubing to increase the kinetic energy of a fluid in an annular region around the outside of the tubing string.
Devices according to embodiments of the present disclosure may be provided as a section of pipe with one or more turbine assemblies integrated into the wall of the pipe, where the section of pipe and integrated turbine assemblies may be referred to herein as a mixing pipe section. A mixing pipe section according to embodiments of the present disclosure may be coaxially connected to other sections of pipe to form a string of downhole tubing. Turbine assemblies provided in a mixing pipe section may include a link rod extending through the wall of the pipe section (from an interior of the mixing pipe section to an exterior of the mixing pipe section), an inner turbine mounted on the link rod in the interior of the mixing pipe section, and an outer impeller mounted on the link rod at the exterior of the mixing pipe section, wherein the inner turbine and outer impeller are rotatable about the link rod.
When mixing pipe sections are incorporated into downhole tubing string and used for a cementing operation, cement (or other fluid) may be flowed through the interior of the tubing string, where the interior flow of fluid may rotate the inner turbine in the interior of the mixing pipe section. Rotation of the inner turbine may, in turn, rotate the outer impeller via the connected link rod, which may mix fluid (e.g., cement) flowing around the outside of the tubing string.
Mixing pipe sections according to embodiments of the present disclosure may be used with various types of downhole tubing strings and in various stages of constructing a well. An exemplary well 100 and cementing steps are shown in
As the well 100 is drilled, sections of the wellbore may be cased. Depending on the depth of the well 100 and other operating parameters, multiple strings of casing may be used to case the well 100. In the example shown in
Each string of casing has an annulus that is located around the exterior of the casing string. The first annulus 120 is the space located between the outer diameter of the conductor casing 108 and the wellbore 106. The wellbore 106 is the exposed portion of the subsurface Earth that is exposed after drilling. The first annulus 120 may be filled completely or partially with cement 136. The second annulus 124 includes both the space located between the outer diameter of the surface casing 110 and the inner diameter of the conductor casing 108 as well as the space between the outer diameter of the surface casing 110 and the wellbore 106. The second annulus 124 may be filled completely or partially with cement 136. The third annulus 126 includes both the space located between the outer diameter of the intermediate casing 112 and the inner diameter of the surface casing 110 as well as the space between the outer diameter of the intermediate casing 112 and the wellbore 106. The third annulus 126 may be filled completely or partially with cement 136. The fourth annulus 128 includes the space located between the outer diameter of the liner casing 114 and the wellbore 106. The fourth annulus 128 may be filled completely or partially with cement 136.
Upon completion of casing the well 100, production tubing 116 may be lowered into the well 100. The space around the production tubing 116 (a fifth annulus 130) and the space within the production tubing 116 make up the interior of the well 100. One or more production packers 138 may be installed within the fifth annulus 130, wherein the production packers 138 are sized such that they fit snugly between the outer diameter of the production tubing 116 and the inner diameter of the liner casing 114. The well 100 depicted in
As fluid (e.g., the drilling fluid 206, spacer fluid 204, cement 136, and displacement fluid 214) is flowed through the interior of the liner casing 114, the fluid may flow through an inner turbine in the turbine assembly 210 to rotate the turbine assembly 210. Rotation of the inner turbine also rotates an outer impeller of the turbine assembly 210, which aids in movement of the fluid flowing around the annulus 128 of the liner casing 114. In such manner, the turbine assembly 210 may improve the flow of fluids around the annulus of a tubing, which may improve cement coverage around the annulus of the tubing when cement is being flowed through the annulus. While
Referring now to
With reference to
As shown in
With reference to
The outer impeller 302, having a plurality of blades 403 extending radially outward from the center of the outer impeller 302, may be disposed in an annulus 306 area around the exterior of the tubular body 304. For example, the portions 312, 320 of the wall 412 may have a planar exterior surface, on which the outer impeller 302 may be disposed. In one or more embodiments, a diameter of the inner turbine 310 may be greater than a diameter of the outer impeller 302.
A link rod 406, which extends through the portions 312, 320 of the wall 312, may connect the inner turbine 310 and the outer impeller 302, such that the center of the inner turbine 310 is mounted to a first end of the link rod 406 and the center of the outer impeller 302 is mounted to a second end of the link rod 406, creating a turbine assembly 300. Further, the inner turbine 310 and the outer turbine 302 may be rotatable about a rotational axis extending through the link rod 406. In one or more embodiments, the link rod may be rigid. The inner turbine 310 and the outer impeller 302 may be rotated in sync via the link rod 406, such that when the inner turbine 310 rotates, the outer impeller 302 also rotates, and vice versa.
Turning now to
The mixing pipe section 602 may include a tubular body 610 having turbine assemblies 634 assembled around the tubular body 610, where each turbine assembly 634 includes an inner turbine 620 connected to an outer impeller 630 via a link rod 632.
Fluid may flow through an interior flow path 612 formed through the tubular body 610 to the bottom of the well, where fluid may be propelled into an annulus 614 around the exterior of the tubular body 610, and flow along an exterior flow path 616. As fluid flows through the interior flow path 612, fluid flow may interact with the blades 618 of the inner turbine 620, such that rotation of the inner turbine 620 is induced. For example, in the embodiment shown, the inner turbine 620 may be positioned in an inset 622 having a depth 624 and extending an axial length 626 of the mixing pipe section 602 to form a channel extending along the inner surface of the mixing pipe section wall. Fluid may flow along interior flow path 612 through the interior of the casing 604 into the inset 622 and the interior of the tubular body 610. As a result, fluid may be propelled through the blades 618 of the inner turbine 620, causing rotation of the inner turbine 620.
Rotation of the inner turbine 620 may rotate the outer impeller 630 via the connected link rod 632. Thus, due to the linked rotation of the inner turbine 620 and outer impeller 630 in a turbine assembly 634, the inner turbine 620 and outer impeller 630 in the same turbine assembly 634 may rotate at the same rotational speed and in the same direction. As fluid flows through the annulus 614 around the exterior of the mixing pipe section 602, fluid may flow through a space 636 formed between the exterior surface of the tubular body 610 and a protective shield 640. As fluid flows through the space 636 within the protective shield 640, the fluid may flow through the outer impellers 630 positioned in the space 636. Because a cementing operation involves directing fluid in a first direction down the interior flow path 612 and then back up in an opposite second direction through the exterior flow path 616, fluid flow through the space 636 within the protective shield 640 may flow from a bottom side of the protective shield 640, through the outer impeller 630, and out of an upper side of the protective shield 640. The rotation of the linked inner turbine 620 may transfer energy to the outer impeller 630, which may create an additional pressure gradient in the annulus 614 and enhance fluid mixing through the exterior flow path 616.
According to embodiments of the present disclosure, an inner turbine 620 and linked outer impeller 630 in a turbine assembly 634 may be designed to have a larger hydrodynamic drag applied to the inner turbine 620 than the outer impeller 630 to ensure the inner turbine 620 is transferring the consumed energy towards the outer impeller 630 to enhance fluid mixing. The relative size and shape of both the inner turbine 620 and outer impeller 630 can be modified to provide optimized energy transferring results. For example, as in the embodiment shown, the diameter of the inner turbine 620 may be larger than the diameter of the outer impeller 630.
In some embodiments, an inner diameter 642 of the hydraulic mixing pipe section 602 may be larger than the inner diameter 628 of the casing 604. In a cementing operation, an example of which is shown in
Initially, a string of pipe may be provided, which may extend through a well, S702. In some embodiments, the string of pipe may be casing. In other embodiments, the string of pipe may be production tubing. In one or more embodiments, the string of pipe may comprise a plurality of pipe sections threadably connected in an axial end-to-end fashion. Further, one or more hydraulic mixing pipe sections 602 may be threadably connected along the plurality of pipe sections in the axial end-to-end configuration. A hydraulic mixing pipe section 602 may have one or more turbine assemblies 634 assembled around the wall of the pipe, where each turbine assembly 634 may include a link rod 632 extending through the wall of the hydraulic mixing pipe section 602, an inner turbine 620 mounted on a first end of the link rod 632, and an outer impeller 630 mounted on a second end of the link rod 632.
An interior flow path 612 may extend axially through the string of pipe, and an exterior annular space, which may be referred to as an annulus 614, may extend axially along an exterior of the string of pipe. In one or more embodiments, the annulus 614 may be formed between the string of pipe and another string of pipe. In other embodiments, the annulus 614 may be formed between the string of pipe and the wellbore. The inner turbine 620 may be mounted in the interior of the string of pipe, interfacing with the interior flow path 612. The outer impeller 630 may interface with the annulus 614 on the exterior of the string of pipe.
A first fluid may be pumped through the interior flow path 612 in order to hydraulically rotate the inner turbine 620, S704. In one or more embodiments, the first fluid may be cement. In other embodiments, the first fluid may be drilling fluid or spacer. In one or more embodiments, a second fluid may be pumped through the interior flow path 612 after the first fluid, wherein the second fluid may be different than the first fluid. The first fluid may be moved through the interior flow path 612 to an axial end of the interior flow path 612, where the first fluid may be directed to the annulus 614. In such embodiments, the first fluid may then flow along an exterior flow path 616 through the annulus 614 in an opposite direction than through the interior flow path 612. The movement of the first fluid through the interior flow path 612 may induce hydraulic rotation of the inner turbine 620.
Hydraulic rotation of the inner turbine 620 may be used to drive rotation of an outer impeller 630 via a link rod 632, which connects the inner turbine 620 and outer impeller 630, S706. The relative shape and size of both the inner turbine 620 and the outer impeller 630 may be modified to provide optimal energy transfer from rotation of the inner turbine 620 to the outer impeller 630 in order to create an additional pressure gradient in the annulus 614 (thereby improving fluid flow through the annulus 614). For example, in one or more embodiments, a diameter of the inner turbine 620may be larger than a diameter of the outer impeller 630 to provide an increased pressure gradient in the annulus 614 as the outer impeller 630 is rotated by the inner turbine 620. Additionally, rotation of the outer impeller 630 may break any formed fluid interfaces and may generate highly turbulent kinetic energy in the exterior flow path 616. Rotation of the inner turbine 620 may transfer consumed energy towards the outer impeller 630, which in turn may transfer the energy to the fluid in the annulus 614, resulting in enhanced fluid mixing in the annulus 614. In embodiments where the first fluid is cement, such energy transfer and increased pressure gradient may help mix the cement into a homogenous fluid, S708, and ensure better cement distribution across the annulus 614.
In one or more embodiments, the outer impeller may be covered with a protective shield 640. In some embodiments, the first fluid may be cement, however there are other embodiments in which the first fluid may be drilling fluid or spacer, for example. Additionally, method 700 may be utilized for improved hydraulic mixing of cement during a cementing operation. However, there are many other applications for method 700. For example, method 700 may also improve drilling fluid removal during spacer displacement.
Embodiments of the present disclosure may provide at least one of the following advantages. In cementing operations, cement should be properly distributed across the entire casing to cement the casing in place. As such, it is beneficial for the cement to be properly mixed into a homogenous fluid. Hydraulic mixing pipe sections according to embodiments of the present disclosure may improve mixing of cement in the annulus around a casing (or other string of tubing) by transferring kinetic energy from a fluid flowing through an interior of the pipe section to a fluid flowing in the opposite direction through an exterior annular space. This transfer of kinetic energy may improve cement mixing, which may lead to improved cement distribution, improved quality of cement operations, reduced overall time of cement operations, and a reduced cost of cement operations.
Although only a few example embodiments 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.
