Patent Application
20240254852
Wells for hydrocarbon production or other applications are completed and made ready for production by cementing a casing within the wellbore and inserting a production tubing string within the casing. Hydrocarbons or other fluids can be produced from a subterranean formation up through the production tubing string.
In a conventional completion, production packers are positioned on the production tubing string to isolate and seal the annulus around the exterior of the production tubing. In a so-called “cemented completion,” in contrast, isolation of the annulus around the exterior of the production tubing is accomplished by cementing the production tubing within the wellbore. In some cemented completions, no production packers are used, as the cement around the production tubing string acts to center the production tubing string and seal the annulus such that no packers are necessary.
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 method. The method may include positioning a casing into a wellbore, pumping cement through the casing to cement the casing in the wellbore, and positioning a casing hanger within a casing head spool that is part of a surface wellhead assembly at an uphole end of the wellbore, wherein the casing hanger is attached to an uphole end of the casing. The method may also include positioning a production tubing string within the casing within the wellbore, the production tubing string comprising a plurality of production tubing segments, and attaching an uphole end of the production tubing string to a lower end of a rotating inner mandrel of a production tubing hanger, wherein the production tubing hanger is configured be positioned within a tubing head spool positioned above the casing head spool within the surface wellhead assembly, wherein the rotating inner mandrel is configured to rotate within a non-rotating housing of the production tubing hanger, and wherein the non-rotating housing of the production tubing hanger is fluted. The method may further include rotating the production tubing string by rotating a landing joint attached to an upper end of the rotating inner mandrel, wherein the landing joint comprises a production tubing segment, and while rotating the production tubing string, pumping cement through the production tubing string to at least partially cement the production tubing string within the wellbore.
In another aspect, embodiments disclosed herein relate to a hydrocarbon production system. The hydrocarbon production system may include a casing hanger positioned within a casing head spool that is part of a surface wellhead assembly at an uphole end of a wellbore, a casing cemented into the wellbore, wherein an upper end of the casing is attached to the casing hanger, and a production tubing hanger configured to be positioned within a tubing head spool positioned above the casing head spool within the surface wellhead assembly. The production tubing hanger may include a rotating inner mandrel within a non-rotating housing, the rotating inner mandrel comprising a mandrel collar extending circumferentially from an outer surface of the rotating inner mandrel and in contact with a bearing positioned between the rotating inner mandrel and the non-rotating housing, where the non-rotating housing comprises one or more flutes integrally formed into a first end of the non-rotating housing, wherein the one or more flutes are configured to improve fluid flow. The hydrocarbon production system may also include an upper seal element and a lower seal element positioned within the production tubing hanger and within an annular space between the rotating inner mandrel and the non-rotating housing, the upper seal element positioned above the mandrel collar and the lower seal element positioned below the mandrel collar. The hydrocarbon production system may further include a production tubing string positioned within the casing, wherein an upper end of the production tubing string is attached to a lower end of the rotating inner mandrel, wherein the production tubing string comprises a plurality of production tubing segments, and wherein the production tubing string is at least partially cemented into the wellbore by pumping cement into the production tubing string while the production tubing string is rotated, and wherein rotation of the production tubing string is by rotating a landing joint comprising a production tubing segment attached to an upper end of the rotating inner mandrel.
In yet another aspect, embodiments disclosed herein relate to a production tubing hanger. The production tubing hanger may include a non-rotating housing, comprising one or more flutes integrally formed into a first end of the non-rotating housing, wherein the one or more flutes are configured to improve fluid flow. The production tubing hanger may also include a rotating inner mandrel disposed within the non-rotating housing, a bearing section configured to rotate the rotating inner mandrel within the non-rotating housing, and a rotation lock. The production tubing hanger may further include one or more upper seal elements disposed in an annulus formed between the non-rotating housing and the rotating inner mandrel, and one or more lower seal elements disposed in the annulus formed between the non-rotating housing and the rotating inner mandrel.
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.
In the following description of
In one aspect, embodiments disclosed herein relate to a fluted rotating tubing hanger for cemented completion applications. In particular, embodiments disclosed herein relate to a fluted rotating tubing hanger configured to rotate the tubing hanger during a cementing procedure. Further, embodiments disclosed herein relate to a fluted rotating tubing hanger configured to take returns through integrated flutes in the tubing hanger up into a blowout preventer flow line, reducing downhole equivalent circulation density (ECD) and frictional pressure drop.
In contrast to a conventional completion (wherein production packers are positioned on the production tubing string to isolate and seal the annulus around the exterior of the production tubing), in a so-called “cemented completion,” isolation of the annulus around the exterior of the production tubing is accomplished by cementing the production tubing within the wellbore. In a cemented completion, the cement layer isolates the annulus between the exterior of the production tubing string and the wellbore (and/or between the exterior of the tubing string and the interior of the liner or casing). In some cemented completions, no production packers are attached to the production tubing. In some cemented completions, production packers are used in conjunction with the cement layer around the production tubing to provide an additional mechanical barrier.
Rotation of the production tubing string during the cementing of the production tubing string in the wellbore for a cemented completion can ensure a more even distribution of cement in the annulus between the exterior of the production tubing string and the wellbore, particularly in deep, horizontal, and/or highly deviated wells. This can, in turn, improve sealing effectiveness of the cement sheath since it is the primary barrier in this type of completion.
In addition, rotation of the production tubing string as the string is being landed at its final depth can help to prevent the string from becoming stuck and/or free the string if stuck during such lowering operations.
The production tubing hanger, system, and method of the present disclosure allows for rotation of the production tubing string both during landing operations and during cementing operations for a cemented completion well system. In accordance with an embodiment of the present disclosure, no specialized rotation tool is required. Instead, rotation can be via a standard landing joint. An anti-rotation mechanism is included within the production tubing hanger to enable removal of the landing joint.
In accordance with an embodiment of the present disclosure, upper and lower seal elements are included within the housing of the production tubing hanger to prevent migration of fluids in the annulus between the rotating inner mandrel and the housing. Thus, no separate pack-off or other additional external sealing components are required to prevent such migration through the annulus around the exterior of the rotating inner mandrel.
The rotating tubing hanger of the present disclosure can also be utilized in other completion types (such as conventional completions) in other situations where a rotation of the production tubing string is desired.
More specifically, the embodiment illustrated in
Referring to
Surface wellhead assembly 120 is positioned at a surface location at an uphole end of wellbore 102. Surface wellhead assembly 120 includes a casing hanger within a casing spool. After cementing the casing in the wellbore, the top end of the casing is attached to the casing hanger. Surface wellhead assembly 120 is described in more detail in reference to
A liner 114 can be positioned in the wellbore and cemented into place using conventional cementing techniques as described above with respect to casing string 110. In an embodiment of the present disclosure, liner 114 is a 7″ liner. In the illustrated embodiment, the top of liner 114 is proximate to the bottom end of casing string 110.
Production tubing string 130 comprises a plurality of production tubing segments 132. After casing string 110 and liner 114 have been cemented within the wellbore, production tubing string 130 is lowered into the wellbore within casing string 110, segment by segment. Centralizers (not shown) are used to centralize production tubing string 130 within wellbore 102. In an embodiment of the present disclosure, production tubing string 130 is a 4½″ production tubing string.
As production tubing string 130 approaches its final depth and the final (top) tubing segment is attached to production tubing string 130, the top end of the top tubing segment is attached to a production tubing hanger 140. More specifically, production tubing hanger 140 (which is described in more detail in
A lower end of a landing joint 160 is made up to the mandrel upper end of production tubing hanger 140. In some embodiments, landing joint 160 comprises a production tubing segment similar or identical to the production tubing segments which comprise production tubing string 130.
A top drive (not shown) supports the landing joint 160 as landing joint 160, production tubing hanger 140, and production tubing string 130 are lowered to their final position. As the production tubing hanger 140 approaches surface wellhead assembly 120, the top drive can impart rotation in landing joint 160 which in turn rotates the rotating inner mandrel of production tubing hanger 140, which in turn rotates production tubing string 130. Such rotation can help prevent production tubing string 130 from becoming stuck in the wellbore during such lowering operations, and/or free production tubing string 130 if stuck, particularly if wellbore 102 is a long, deep, and/or highly deviated wellbore.
When production tubing string 130 has reached its final depth, as shown in
Referring to
While the (non-rotating) housing of production tubing hanger 140 is locked into place in the surface wellhead assembly 120, the rotating inner mandrel within the non-rotating housing of production tubing hanger 140 can be rotated by landing joint 160 (driven by a top drive or other suitable mechanism) which in turn rotates production tubing string 130. Rotation of production tubing string 130 during the cementing operations (i.e., while cement is flowing from the bottom end of production tubing string 130 and into annulus 142) can ensure more even distribution of cement in the annulus 142 between the exterior of the production tubing string and the wellbore, particularly in deep, horizontal, and/or highly deviated wells. This can in turn improve the sealing effectiveness of the cement as against high bottom-hole pressures.
After cementing of production tubing string 130 is completed, the remaining steps of the completion can be completed via conventional means (including but not limited to perforating operations to provide a path through which hydrocarbons can travel from the formation into production tubing string 130). Oil, gas, and or other hydrocarbon fluids from the subterranean formation into which wellbore 102 has been drilled can be produced through production tubing string 130. During such production, produced hydrocarbons are in contact with the interior surface of production tubing string 130.
Referring to
Rotating inner mandrel 210 includes a mandrel collar 214 which extends circumferentially from an outer surface of rotating inner mandrel 210 and which prevents upward or downward movement of rotating inner mandrel 210 within housing 202. In the illustrated embodiment, mandrel collar 214 is in contact with bearings 216 which reduce friction between rotating inner mandrel 210 and housing 202 as rotating inner mandrel 210 rotates about axis 212.
Production tubing hanger 140 further includes lower seal element 240 and upper seal element 244 positioned in the annulus 248 between rotating inner mandrel 210 and housing 202. In the illustrated embodiment, lower seal element 240 is positioned in the housing below (in the downhole direction of) mandrel collar 214 and upper seal element 244 is positioned in the housing above mandrel collar 214. Lower seal element 240 and upper seal element 244 are configured to prevent the migration of fluids through annulus 248. Outer seals 260 are positioned on the outer surface of housing 202. In the illustrated embodiment, because of lower seal element 240 and upper seal element 244 are part of production tubing hanger 140, no pack-off or other separate sealing component around or above production tubing hanger 140 is necessary to prevent fluid migration through annulus 248. Junk bonnet 250 is positioned at an upper end of production tubing hanger 140 around rotating inner mandrel 210 and prevents dust or debris from entering annulus 248.
Production tubing hanger 140 further includes anti-rotation locks 230 which allows rotation of rotating inner mandrel 210 in one direction but prevents rotation of rotating inner mandrel 210 in the opposite direction. By preventing rotation of rotating inner mandrel 210 in one direction, anti-rotation locks 230 enables landing joint 160 to be removed from the mandrel upper end 220 by rotating landing joint 160 in the opposite direction than the thread connection direction of upper threads 222 (for example, counterclockwise for clockwise threads) as the locks prevent rotation of rotating inner mandrel 210 in that direction. Such removal can be, for example, after production tubing string 130 is cemented within the wellbore.
In one or more embodiments, production tubing hanger 600 may have a rotating inner mandrel 210 disposed within a housing 202. One or more flutes 602 may be integrally formed into a lower end of the housing 202. The one or more flutes 602 may reduce additional back pressure on the well, reduce downhole equivalent circulating density (ECD), and reduce frictional pressure drop since returns may flow through the one or more flutes 602 into the blowout preventer flow line.
Referring to
Surface wellhead assembly 120 further includes tubing head spool 420 above casing head spool 412 and into which production tubing hanger 140 is positioned. As also described in reference to
Tie-down bolts 422 lock production tubing hanger 140 within tubing head spool 420. Outer seals 260 seal the outer portion of production tubing hanger 140 against the inner surface of tubing head spool 420. Christmas tree bonnet 430 positioned above tubing head spool 420 prevents dust and debris from entering tubing head spool 420.
Method 500 of
At step 506, a production tubing string is positioned within the casing within the wellbore. The production tubing string is made of up multiple production tubing segments.
At step 508, an uphole end of the production tubing string is attached to a lower end of a rotating inner mandrel of a production tubing hanger. In some embodiments, the production tubing hanger can be production tubing hanger 140 as described in reference to
At step 510, a landing joint is attached to an upper end of the rotating inner mandrel of the production tubing hanger. In some embodiments, the landing joint can be a segment of production tubing. At step 512, the production tubing string is lowered to its final depth, and the production tubing can be rotated if necessary or desired as the production tubing string is lowered, to avoid the production tubing string from becoming stuck or to free it if it has become stuck. The production tubing can be rotated by the top drive (or other suitable rotating mechanism) rotating the landing joint which in turn rotates the rotating inner mandrel. As the production tubing string reaches its final depth, at step 514, the production tubing hanger is positioned within the tubing head spool and locked into place with tie-down bolts or other suitable apparatus.
At step 516, cement is pumped down the central bore of the production tubing string and into the annulus between the production tubing string and the wellbore (and/or between the production tubing string and the wellbore or the interior of the liner and/or casing). As described in reference to
After step 516 is completed the remaining steps of the completion can be completed via conventional means. At step 518, oil, gas, and or other hydrocarbon fluids from the subterranean formation into which wellbore has been drilled can be produced through the production tubing string.
Embodiments of the present disclosure may provide at least one of the following advantages.
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. 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 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.
