Systems and Methods For Rotating a Casing String In a Wellbore

Abstract

An offline casing string rotation system can include a ring gear configured to be coupled to a rotatable mandrel casing hanger, where the rotatable mandrel casing hanger is part of a wellhead assembly and is coupled to a top end of a casing string. The offline casing string rotation system can also include a gear driving assembly moveably coupled to the ring gear, wherein the gear driving assembly, when enabled, causes the gear to rotate the rotatable mandrel casing hanger.

Description

TECHNICAL FIELD

The present application is related to wellbore operations and, more particularly, to systems and methods for rotating a casing string in a wellbore.

BACKGROUND

During drilling and completions operations of a hydrocarbon producing wellbore, well casing is typically run to a desired depth while drilling a wellbore, and then cement is generally used to solidify the casing within the drilled wellbore. The casing is used to serve any of a number of purposes, including but not limited to provide strength for installation of wellbore assemblies at the surface, provide pressure integrity, seal off low strength formations, seal off leaky formations, and protect oil-producing zones and non-oil-producing zones from contamination.

During the cementing operation, a cement slurry is pumped through the inner bore of the well casing, out its distal end, and into the annulus formed between the well casing and the wellbore. The cement is then pumped back up toward the surface within the annulus. In the cementing-in of casing, a common problem encountered is how to provide a better cement bond between the casing, the wellbore and the cement in the annulus to overcome potential problems such as water migration between various zones.

It is common practice to rotate casing in order to enhance wellbore cementing. Rotating casing has been found to noticeably enhance the bond between the casing and the cement. However, high torque must be generated to rotate the casing from the surface, and so the rig equipment used to drill the wellbore and set the casing string within the wellbore is used to rotate the casing. This results in increased costs because rig rental fees are high. Avoidance of excess rig fees due to extended use is desirable.

SUMMARY

In general, in one aspect, the disclosure relates to an offline casing string rotation system. The offline casing string rotation system can include a ring gear configured to be coupled to a rotatable mandrel casing hanger, wherein the rotatable mandrel casing hanger is part of a wellhead assembly and is coupled to a top end of a casing string. The offline casing string rotation system can also include a gear driving assembly moveably coupled to the ring gear, wherein the gear driving assembly, when enabled, causes the gear to rotate the rotatable mandrel casing hanger

In another aspect, the disclosure relates to a method for rotating a casing string. The method can include coupling a ring gear to a rotatable mandrel casing hanger, wherein the rotatable mandrel casing hanger is part of a wellhead assembly and is coupled to a top end of a casing string. The method can also include engaging a gear driving mechanism with the ring gear, wherein the gear driving mechanism is part of a gear driving assembly. The method can further include operating a drive unit coupled to the gear driving mechanism, wherein the drive unit, when operating and using the gear driving mechanism and the ring gear, rotates the rotatable mandrel casing hanger.

In yet another aspect, the disclosure relates to a system for cementing a casing string in a wellbore. The system can include a wellhead assembly disposed at an entry point of the wellbore, wherein the wellhead assembly comprises a rotatable mandrel casing hanger coupled to a top end of the casing string. The system can also include a cement head coupled to a top end of the wellhead assembly. The system can further include an offline casing string rotation system coupled to the rotatable mandrel casing hanger. The offline casing string rotation system can include a ring gear coupled to the rotatable mandrel casing hanger. The offline casing string rotation system can also include a gear driving assembly moveably coupled to the ring gear, wherein the gear driving assembly, when enabled, causes the gear to rotate the rotatable mandrel casing hanger.

These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positions may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements.

FIG. 1 shows a system for setting casing in a wellbore before a cementing operation according to the current art.

FIG. 2 shows a sectional side view of a casing program according to the current art.

FIG. 3 shows a system for a wellbore cementing operation according to certain example embodiments.

FIGS. 4A and 4B show various views of an offline system for a wellbore cementing operation according to certain example embodiments.

FIG. 5 shows an offline system that includes the offline system of FIGS. 4A and 4B with the addition of a ring gear.

FIG. 6 an offline system that includes shows the offline system of FIG. 5 with the addition of a cement head support system.

FIG. 7 shows an offline system that includes the offline system of FIG. 6 with the addition of a cement head.

FIG. 8 shows an offline system that includes the offline system of FIG. 7 with the addition of a gear drive assembly.

FIG. 9 shows an offline casing string rotation system (without the drive unit) according to certain example embodiments.

FIG. 10 shows another offline casing string rotation system (without the drive unit) according to certain example embodiments

DESCRIPTION OF THE INVENTION

The example embodiments discussed herein are directed to systems and methods for rotating a casing string in a wellbore. Wellbores that undergo cementing operations for which example embodiments are used can be drilled and completed to extract a subterranean resource. Examples of a subterranean resource can include, but are not limited to, natural gas, oil, and water. Wellbores for which example embodiments are used for cementing operations can be land-based or subsea. Example embodiments of systems and methods for rotating a casing string in a wellbore can be rated for use in hazardous environments.

As used herein, the term “offline” means that a traditional rig system (e.g., a derrick, a kelly, a drive) is not used to rotate a casing string. Rather, example systems and methods for rotating a casing string, also sometimes referred to herein as offline casing string rotation systems, use other equipment (e.g., gears, shafts, drive units) so that the rig and related equipment can be moved away from the field operation sooner, thereby reducing costs. A user as defined herein can be any person associated with a cementing operation for a wellbore. Examples of a user can include, but are not limited to, an engineer, a company representative, a consultant, an operator, and a mechanic.

An example system for rotating a casing string in a wellbore includes multiple components that are described herein, where a component can be made from a single piece (as from a mold or an extrusion). When a component (or portion thereof) of an example system for rotating a casing string in a wellbore is made from a single piece, the single piece can be cut out, bent, stamped, and/or otherwise shaped to create certain features, elements, or other portions of the component. Alternatively, a component (or portion thereof) of an example system for rotating a casing string in a wellbore can be made from multiple pieces that are mechanically coupled to each other. In such a case, the multiple pieces can be mechanically coupled to each other using one or more of a number of coupling methods, including but not limited to adhesives, welding, fastening devices (e.g., bolts), compression fittings, mating threads, and slotted fittings. One or more pieces that are mechanically coupled to each other can be coupled to each other in one or more of a number of ways, including but not limited to fixedly, hingedly, rotatably, removably, slidably, and threadably.

Components and/or features described herein can include elements that are described as coupling, fastening, securing, or other similar terms. Such terms are merely meant to distinguish various elements and/or features within a component or device and are not meant to limit the capability or function of that particular element and/or feature. For example, a feature described as a “coupling feature” can couple, secure, abut against, fasten, and/or perform other functions aside from merely coupling. In addition, each component and/or feature described herein (including each component of an example offline casing string rotation system) can be made of one or more of a number of suitable materials, including but not limited to metal (e.g., stainless steel), ceramic, rubber, glass, and plastic.

A coupling feature (including a complementary coupling feature) as described herein can allow one or more components (e.g., a housing) and/or portions of an example system for rotating a casing string in a wellbore to become mechanically coupled, directly or indirectly, to another portion of the system for rotating a casing string in a wellbore and/or a component (e.g., a rotatable mandrel casing hanger) of a wellhead assembly. A coupling feature can include, but is not limited to, a portion of a hinge, an aperture, a recessed area, a protrusion, a slot, a spring clip, a tab, a detent, and mating threads. One portion of an example system for rotating a casing string in a wellbore can be coupled to another portion of the system for rotating a casing string in a wellbore and/or a component of wellhead assembly by the direct use of one or more coupling features.

In addition, or in the alternative, a portion of an example system for rotating a casing string in a wellbore can be coupled to another portion of the system for rotating a casing string in a wellbore and/or a component of a wellhead assembly using one or more independent devices that interact with one or more coupling features disposed on a component of the system for rotating a casing string in a wellbore. Examples of such devices can include, but are not limited to, a pin, a hinge, a fastening device (e.g., a bolt, a screw, a rivet), an adapter, and a spring. One coupling feature described herein can be the same as, or different than, one or more other coupling features described herein. A complementary coupling feature as described herein can be a coupling feature that mechanically couples, directly or indirectly, with another coupling feature.

When used in certain systems (e.g., for certain subterranean field operations), example embodiments can be designed to help such systems comply with certain standards and/or requirements. Examples of entities that set such standards and/or requirements can include, but are not limited to, the Society of Petroleum Engineers, the American Petroleum Institute (API), the International Standards Organization (ISO), and the Occupational Safety and Health Administration (OSHA). Also, as discussed above, example systems for rotating a casing string in a wellbore can be used in hazardous environments, and so example systems for rotating a casing string in a wellbore can be designed to comply with industry standards that apply to hazardous environments.

If a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure can be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component can be substantially the same as the description for the corresponding component in another figure. The numbering scheme for the various components in the figures herein is such that each component is a three-digit or a four-digit number and corresponding components in other figures have the identical last two digits. For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and/or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure.

Further, a statement that a particular embodiment (e.g., as shown in a figure herein) does not have a particular feature or component does not mean, unless expressly stated, that such embodiment is not capable of having such feature or component. For example, for purposes of present or future claims herein, a feature or component that is described as not being included in an example embodiment shown in one or more particular drawings can be capable of being included in one or more claims that correspond to such one or more particular drawings herein.

Example embodiments of systems for rotating a casing string in a wellbore will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments of systems for rotating a casing string in a wellbore are shown. Systems for rotating a casing string in a wellbore may, however, be embodied in many different forms and should not be construed as limited to the example embodiments set forth herein. Rather, these example embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of systems for rotating a casing string in a wellbore to those of ordinary skill in the art. Like, but not necessarily the same, elements (also sometimes called components) in the various figures are denoted by like reference numerals for consistency.

Terms such as “first”, “second”, “outer”, “inner”, “top”, “bottom”, “upper”, “lower”, “distal”, “proximal”, “on”, and “within” are used merely to distinguish one component (or part of a component or state of a component) from another. This list of terms is not exclusive. Such terms are not meant to denote a preference or a particular orientation, and they are not meant to limit embodiments of systems for rotating a casing string in a wellbore. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention 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.

FIG. 1 shows a system 100 for setting casing in a wellbore before a cementing operation according to the current art. The system 100 includes a wellbore 122 that is disposed in a subterranean formation 110. The wellbore 122 is defined by a wall 109. The wellbore 122 is drilled using a derrick 105 and other field equipment 190 (e.g., a tool pusher, a clamp, a tong, drill pipe, casing pipe, a drill bit, a drill bit, and a fluid pumping system). Some of this field equipment 190 is located above a surface 108, while other field equipment 190 is located within the wellbore 122 as the wellbore 122 is drilled. Once the wellbore 122 (or a section thereof) is drilled, a casing string 115 is inserted into the wellbore 122 and subsequently cemented to the wellbore 122 to stabilize the wellbore 122 and allow for the extraction of subterranean resources (e.g., oil, natural gas) from the subterranean formation 110. At times, as the cement is being pumped into the wellbore, the casing string 115 is rotated to help ensure that the various gaps between the wall 109 of the wellbore 122 and the outer surface of the casing string 115 are filled.

The surface 108 can be ground level for an on-shore (also called land-based) application (as in this case) and the sea floor for an off-shore application. The point where the wellbore 122 begins at the surface 108 can be called the entry point. While not shown in FIG. 1, there can be multiple wellbores 122, each with their own entry point but that are located close to the other entry points, drilled into the subterranean formation 110. In such a case, the multiple wellbores 120 can be drilled at the same pad location.

The subterranean formation 110 can include one or more of a number of formation types, including but not limited to shale, limestone, sandstone, clay, sand, and salt. In certain embodiments, a subterranean formation 110 can include one or more reservoirs in which one or more resources (e.g., oil, gas, water, steam) can be located. One or more of a number of field operations (e.g., fracking, coring, tripping, drilling, setting casing, extracting downhole resources) can be performed to reach an objective of a user with respect to the subterranean formation 110.

The wellbore 122 can have one or more of a number of segments, where each segment can have one or more of a number of dimensions. Examples of such dimensions can include, but are not limited to, size (e.g., diameter) of the wellbore 122, a curvature of the wellbore 122, a total vertical depth of the wellbore 122, a measured depth of the wellbore 122, and a horizontal displacement of the wellbore 122.

A wellbore 122 can also undergo multiple cementing operations, where each cementing operation covers part or all of a segment of the wellbore 122 or multiple segments of the wellbore 122. In such a case, the wellbore 122 can have a casing program using multiple casing strings at different depths within the wellbore 122. For example, FIG. 2 shows a sectional side view of a casing program 214 according to the current art. Specifically, the casing program 214 of FIG. 2 includes casing string 215-1, casing string 215-2, casing string 215-3, casing string 215-4, and casing string 215-5.

All of the casing strings 215 of the casing program 214 of FIG. 2 start at the surface 208. The casing string 215-1 is the shortest but also the widest. The casing string 215-2, which is disposed within the casing string 215-1, is longer and slightly narrower than the casing string 215-1. The casing string 215-3, which is disposed within the casing string 215-2, is longer and slightly narrower than the casing string 215-2. The casing string 215-4, which is disposed within the casing string 215-3, is longer and slightly narrower than the casing string 215-3. The casing string 215-5, which is disposed within the casing string 215-4, is longer and slightly narrower than the casing string 215-4.

Referring back to FIG. 1, after a casing string 115 is inserted into the wellbore 122, cement is pumped (using field equipment 190) into the cavity 120 of the casing string 115. Once the cement exits the cavity of the casing string 115, it is forced (e.g., by the end of the wellbore 122, by a plug inserted into the wellbore 122) up the annulus 195 of the casing string 115, filling the gap between the wall 109 and the outer surface of the casing string 115. The goal of a cementing operation is to put wet cement in the annulus 195. Specialized field equipment 190, positioned at the surface 108 near the entry point of the wellbore 122, can be used in a subterranean cementing operation. Such field equipment 190 can include, but is not limited to, mixers, pumps, storage tanks, motors, generators, and piping.

When the cement sets and dries, a secure bond is created between the subterranean formation 110 and the casing string 115. As mentioned above, in some cases, an operator will rotate the casing string 215 during the cementing process. In the current art, rotating the casing string 215 is accomplished using the derrick 105 and other field equipment 190, which adds to the expensive fees associated with renting the derrick 105 and other field equipment 190.

The casing string 115 includes a number of casing pipes that are coupled to each other (directly or indirectly using a collar, sleeve, or other coupling device) end-to-end to form the casing string 115. Each end of a casing pipe has mating threads (a type of coupling feature) disposed thereon, allowing a casing pipe to be mechanically coupled (directly or indirectly) to another casing pipe in an end-to-end configuration.

Each casing pipe of the casing string 115 can have a length and a width (e.g., outer diameter). The length of a casing pipe can vary. For example, a common length of a casing pipe is approximately 40 feet. The length of a casing pipe can be longer (e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width of a casing pipe can also vary and can depend on the cross-sectional shape of the casing pipe. For example, when the cross-sectional shape of a casing pipe is circular, which is commonly the case, the width can refer to an outer diameter, an inner diameter, or some other form of measurement of the casing pipe. Examples of a width in terms of an outer diameter of a casing pipe can include, but are not limited to, 4½ inches, 7 inches, 7⅝ inches, 8⅝ inches, 10¾ inches, 13⅜ inches, 14 inches, and 30 inches. Under a casing program, as discussed above with respect to FIG. 2, the larger widths of the casing pipe are closer to the entry point at the surface 108, and the width gradually decreases by segment moving toward the distal end of the wellbore 122.

The size (e.g., width, length) of the casing string 115 can be based on the information gathered using some of the field equipment 190 with respect to the subterranean wellbore 122. The walls of the casing string 115 have an inner surface that forms a cavity 120 that traverses the length of the casing string 115. Each casing pipe of the casing string 115 can be made of one or more of a number of suitable materials, including but not limited to stainless steel. As discussed above, there is a gap 195, also called an annulus 195, between the outer surface of the casing string 115 and the wall 109 of the wellbore 122. In some cases, stabilizers (not shown) or similar devices can be inserted along with the casing pipes and/or integrated with the casing pipe. These stabilizers help to keep the casing string 115 relatively centered within the wellbore 122.

FIG. 3 shows a system 300 for a wellbore cementing operation according to certain example embodiments. Referring to FIGS. 1 through 3, the system 300 of FIG. 3 includes a wellhead assembly 340, a casing string 315, a cement head 385, and an example offline casing string rotation system 380. The casing string 315 is substantially the same as the casing strings discussed above with respect to FIGS. 1 and 2.

The wellhead assembly 340 is a combination of multiple components that are used to facilitate one or more operations (e.g., drilling, setting casing, cementing) in the wellbore 122. Examples of such components of the wellhead assembly 340 can include, but are not limited to, a blowout preventer (BOP) stack (and associated equipment), a housing outlet, a valve, an inlet port, an outlet port, a ring gasket, a tubing head, a casing bowl, a crossover flange, and a hanger. In addition, in this example, the wellhead assembly 340 includes a rotatable mandrel casing hanger 350, which is coupled (e.g., threadably) to the top end of the tubing string 315. The rotatable mandrel casing hanger 350 stays fixedly coupled to part of the wellhead assembly 340 while also allowing an operator to rotate the casing string 315 during cementing operations. Rotatable mandrel casing hangers 350 are well known in the art using traditional rig equipment and can have any of a number of different configurations. Regardless of configuration, the rotatable mandrel casing hanger 350 is rated to handle sufficient pressure (e.g., 15,000 psi) and rotational torque (e.g., 40,000 ft-lbf) required for a cementing operation. Any rotatable mandrel casing hanger 350, whether currently known or developed in the future, can be used with example offline casing string rotation systems.

Further, in this example, the wellhead assembly 340 can include one or more optional sensor devices 360. Each sensor device 360 includes one or more sensors that measure one or more parameters (e.g., position, azimuth, rotations, rotational speed, vibration, pressure, flow rate, torque). Measurements made by a sensor of a sensor device 360 can be sent to a controller for use during a field operation, such as a cementing operation. For example, a sensor device 360 of the wellhead assembly 340 can be configured to measure the rate of rotation of the rotatable mandrel casing hanger 350 or the casing string 315. A user (e.g., a cementing engineer, an operator) can then use this information to determine if an adjustment is needed for the cementing operation. If, for example, the rate of rotation of the rotatable mandrel casing hanger 350, as measured by a sensor device 360 of the wellhead assembly 340, is 4 rpm, the operator can increase the power to the drive unit 335 of the gear drive assembly 330 until the sensor device 360 measures at least 5 rpm, which is considered by the cementing engineer the minimum amount of rotation required to optimize the cementing operation. In some cases, a sensor device 360 can be part of another assembly or system, or can be a stand-alone device, rather than be part of the wellhead assembly 340.

As another example, a sensor of a sensor device 360 can be configured to measure the torque applied to a component (e.g., the rotatable mandrel casing hanger 350, the casing string 315) of the system 300. Such information can be useful to a user to determine if the offline casing string rotation system 380 is operating at a proper level. For instance, if a user determines that an optimal range of torque applied to the rotatable mandrel casing hanger 350 is between 10,000 ft-lbs and 40,000 ft-lbs, the torque measurement made by the sensor device 360 can inform the user as to whether the drive unit 335 needs more power, needs less power, or requires no change during a cementing operation.

The cement head 385 is also known in the art and provides the cement used in the cementing operation. The cement head 385 is coupled (e.g., using bolts) to a top end of the wellhead assembly 340. The cement head 385 can have any of a number of configurations and use any of a number of different components (e.g., valves, gauges, inlet channels, pipes). In some ways, the cement head 385 can act as a manifold for receiving cement from multiple sources and delivering the cement to the wellhead assembly 340 through a single outlet channel.

The example offline casing string rotation system 380 of the system 300 is configured to rotate the rotatable mandrel casing hanger 350 (and so also the casing string 315 coupled to the rotatable mandrel casing hanger 350) without a traditional rig and its various components. The example rotatable mandrel casing hanger 350 includes multiple components. For example, in this case, the rotatable mandrel casing hanger 350 includes a gear 375, a gear driving mechanism 325, a shaft 327, and a drive unit 335.

The gear 375 is coupled to a rotatable portion of the rotatable mandrel casing hanger 350. The gear 375 can be coupled to the rotatable mandrel casing hanger 350 in one or more of a number of ways. For example, the gear 375 can be coupled to the rotatable mandrel casing hanger 350 using multiple bolts. As another example, the gear 375 can be welded to the rotatable mandrel casing hanger 350. Regardless of how the gear 375 is coupled to the rotatable mandrel casing hanger 350, the gear 375 and the rotatable portion of the rotatable mandrel casing hanger 350 to which the gear 375 is coupled remain in a fixed position relative to each other.

In addition, the gear 375 includes one or more engagement features 373 that are configured to be engaged by complementary engagement features 323 of the gear driving mechanism 325. For example, the gear 375 can be a ring gear having an inner surface that abuts against the rotatable portion of the rotatable mandrel casing hanger 350 and an outer surface having multiple engagement features 373 in the form of teeth. An example of such a configuration for the gear 375 is shown below with respect to FIG. 9. As another example, the gear 375 can be configured as a worm wheel. An example of such a configuration for the gear 375 is shown below with respect to FIG. 10.

Regardless of the specific configuration of the gear 375, the gear 375 has a mating surface and/or one or more coupling features (e.g., threaded apertures) that are designed to allow the gear 375 to couple, directly or indirectly, to the rotatable portion of the rotatable mandrel casing hanger 350. Further, the gear 375 has multiple engagement features 373 (e.g., teeth) that, when engaged by complementary engagement features 323 of the gear driving mechanism 325, cause the gear 375 to move (in this case, rotate along the axis defined along the length of the rotatable mandrel casing hanger 350). Since the gear 375 is fixedly coupled to the rotatable portion of the rotatable mandrel casing hanger 350, as the gear 375 rotates, so does the rotatable mandrel casing hanger 350, which in turn forces the casing string 315 to rotate.

The gear driving mechanism 325 of the offline casing string rotation system 380 also can have any of a number of configurations. Some of these configurations are based on the configuration of the engagement features 373 of the gear 375. For example, the gear driving mechanism 325 includes multiple engagement features 323 that complement the engagement features 373 of the gear 375. As a specific example, as shown in FIG. 9 below, the gear driving mechanism 325 can be a pinion with engagement features 323 in the form of teeth. As another specific example, the gear driving mechanism 325 can be a worm with a continuous engagement feature 323. In addition, the gear driving mechanism 325 can include at least one coupling feature (e.g., one or more threaded apertures, a detent, a compression fitting, a channel) for receiving and/or fixedly coupling to the shaft 327.

In order to generate the torque required to rotate the rotatable mandrel casing hanger 350, the size of the gear driving mechanism 325 needs to be appropriate relative to the size of the gear 375. Specifically, in this case, the size of the gear driving mechanism 325 is smaller than the size of the gear 375. As a result, the gear driving mechanism 325 rotates multiple times for each rotation of the gear 375. Consequently, the gear driving mechanism 325 has fewer engagement features 323 compared to the number of engagement features 373 of the gear 375.

The shaft 327 of the offline casing string rotation system 380 is configured to provide mechanical coupling between the gear driving mechanism 325 and the drive unit 335. The shaft 327 can have any of a number of cross-sectional shapes, including but not limited to circular, square, octagonal, and triangular. The cross-sectional shape of the shaft 327 can be uniform or variable along its length. As discussed above, one end (e.g., the distal end) of the shaft 327 is fixedly coupled to the gear driving mechanism 325. The other end (e.g., the proximal end) of the shaft 327 is fixedly coupled to the drive unit 335. In this way, as the drive unit 335 rotates the shaft 327, the shaft 327 rotates the gear driving mechanism 325.

The drive unit 335 of the offline casing string rotation system 380 provides the rotational force to the shaft 327 to drive the gear driving mechanism 325. The drive unit 335 can be actuated by any of a number of resources. For example, the drive unit 335 can operate hydraulically. As another example, the drive unit 335 can include a motor powered by electricity. In such a case, the electricity can be provided by a battery, diesel fuel, propane, natural gas, or some other source of fuel and/or power. The drive unit 335 can operate at a fixed speed (e.g., 3600 rpm) or a variable speed. The drive unit 335 can be controlled manually (e.g., on/off switch) or by a controller. The drive unit 335 is configured to have enough horsepower (translated to torque through the shaft 327 and the gear driving mechanism 325) to sufficiently rotate the casing string 315.

FIGS. 4A and 4B show various views of an offline system 400 for a wellbore cementing operation according to certain example embodiments. Specifically, FIG. 4A shows a sectioned side view of the system 400, and FIG. 4B shows a side view of the system 400. Referring to FIGS. 1 through 4B, the system 400 of FIGS. 4A and 4B includes a wellhead assembly 440, a casing string 415, a mandrel retention mechanism 457, and multiple seals 459. The wellhead assembly 440 includes a sensor device 460 and a rotatable mandrel casing hanger 450 coupled to the casing string 415.

The wellhead assembly 440, the casing string 415, the sensor device 460, and the rotatable mandrel casing hanger 450 are substantially similar to the wellhead assembly, the casing string, the sensor device, and the rotatable mandrel casing hanger discussed above with respect to FIGS. 1 through 3. For example, the casing string 415 of the system 400 has a cavity 420 that runs along its length and forms an annulus 495 (or gap 495) with an outer wall 494 of the wellhead assembly 440. As another example, the sensor device 460 can be configured to measure the rotational speed of the casing string 415. In this case, the rig equipment and the BOP have been removed from the wellhead assembly 440.

The mandrel retention mechanism 457 is a component or assembly of components that secures the rotatable mandrel casing hanger 450 within the wellhead assembly 400. Since the rotatable mandrel casing hanger 450 is coupled to the casing string 415, which has substantial weight, particularly for greater lengths, the mandrel retention mechanism 457 plays an important role in helping to suspend the casing string 415 until the cement can be pumped into the wellbore and sets. The mandrel retention mechanism 457 is well known in the art and can have any of a number of different configurations. The seals 459 are also known in the art and can have any of a number of forms (e.g., gaskets, O-rings, cured silicone). Each seal 459 is designed to provide a barrier between the adjacent sides to the seal 459. In this way, the seal 459 can prevent elements (e.g., dirt, moisture) from traversing across the seal 459.

FIG. 5 shows an offline system 500 that includes the offline system 400 of FIGS. 4A and 4B with the addition of a ring gear 575. The ring gear 575 is substantially the same as the ring gear 375 discussed above with respect to FIG. 3. In this case, the ring gear 575 is fixedly coupled (e.g., welded, bolted using fastening devices) to an upper portion of the rotatable mandrel casing hanger 450 of the wellhead assembly 440. The shape of the body of the ring gear 575 when viewed from above is circular. The ring gear 575 includes multiple engagement features 573 in the form of teeth that are disposed on its outer surface around the entire perimeter of the ring gear 575.

FIG. 6 an offline system 600 that includes shows the offline system 500 of FIG. 5 with the addition of a cement head support system 683. The cement head support system 683 is an arrangement of one or more mechanical components that couples to the wellhead assembly 440 so that the cement head support system 683 is positioned above the wellhead assembly 440. The cement head support system 683 is designed to hold a cement head, such as was described above with respect to FIG. 3. The cement head support system 683 is well known in the art and can have any of a number of different configurations.

In this case, the cement head support system 683 is configured to cover and abut against part of the top portion of the rotatable mandrel casing hanger 450. The bottom of the cement head support system 683 can be located proximate to the ring gear 575, which is coupled to the top portion of the rotatable mandrel casing hanger 450. The engagement features 573 of the ring gear 575 remain exposed in this configuration. Where the cement head support system 683 abuts against the top portion of the rotatable mandrel casing hanger 450, there can be one or more seals 659 therebetween. Such seals 659 can be positioned in channels disposed in the outer surface of the top portion of the rotatable mandrel casing hanger 450 and/or in an inner surface of the cement head support system 683. The seals 659 can be substantially the same as the seals 459 discussed above with respect to FIGS. 4A and 4B. In this case, the seals 659 can provide the added benefit of facilitating rotation of the rotatable mandrel casing hanger 450 relative to the cement head support system 683.

FIG. 7 shows an offline system 700 that includes the offline system 600 of FIG. 6 with the addition of a cement head 785. The cement head 785 is substantially the same as the cement head 385 discussed above with respect to FIG. 3. The cement head 785 is coupled and disposed over to the cement head support system 683. In this configuration, the bottom of the cement head 785 is located proximate to the ring gear 575, allowing the engagement features 573 of the ring gear 575 to remain exposed. One or more sources of cement can be connected to the cement head 785 to provide the cement used in a cementing operation.

FIG. 8 shows an offline system 800 that includes the offline system of FIG. 7 with the addition of a gear drive assembly 830. The gear drive assembly 830 (including the drive unit 835 and the gear driving mechanism 875) is substantially similar to the gear drive assembly 830 (including the drive unit 335 and the gear driving mechanism 375) of FIG. 3 above. With the engagement features 573 of the ring gear 575 exposed, the engagement features 873 of the gear driving mechanism 875 can engage the engagement features 823 of the ring gear 825. In this case, the shaft (similar to the shaft 327) of the gear drive assembly 830 is hidden from view.

As the drive unit 835 operates, a rotational motion is imposed on the gear driving mechanism 875 through the shaft. As the gear driving mechanism 875 rotates, the engagement features 873 of the gear driving mechanism 875 engage the engagement features 823 of the ring gear 825, forcing the ring gear 825 to rotate. Since the ring gear 825 is fixedly coupled to the upper portion of the rotatable mandrel casing hanger 450, the rotatable mandrel casing hanger 450 rotates the casing string 415, which is fixedly coupled to the rotatable mandrel casing hanger 450. The cement head 785, the cement head support system 683, and the remainder of the wellhead assembly 440 remain in a fixed position as the rotatable mandrel casing hanger 450 and the casing string 415 rotate. As the rotatable mandrel casing hanger 450 and the casing string 415 rotate, cement can be pumped into the wellbore through the cement head 785.

It will be appreciated that the sequence of evolving the example system from FIGS. 4A and 4B to FIG. 8 can also be used to describe a method of creating an example offline casing string rotation system for rotating a casing string. In such a case, the sequence of steps shown from FIGS. 4A and 4B to FIG. 5 to FIG. 6 to FIG. 7 to FIG. 8 can be varied (e.g., combined, made in a different order) without changing the resulting offline casing string rotation system and/or how the resulting system can be used in a cementing operation. In addition, or in the alternative, additional steps can be taken to achieve an example offline casing string rotation system and a method of using such system in a cementing operation.

FIG. 9 shows an offline casing string rotation system 980 (without the drive unit) according to certain example embodiments. Referring to FIGS. 1 through 9, the offline casing string rotation system 980 of FIG. 9 includes a ring gear 975 having multiple engagement features 973 that are evenly distributed along the outer surface of the ring gear 975. The offline casing string rotation system 980 also includes a gear driving mechanism 925 having multiple engagement features 923 that are evenly distributed along the outer surface of the gear driving mechanism 925. The gear driving mechanism 925 in this case is in the form of a pinion so that the offline casing string rotation system 980 has a ring and pinion configuration.

A shaft 927 is fixedly coupled to the gear driving mechanism 925. As the shaft 927 rotates (caused by a drive unit, not shown in FIG. 9), the gear driving mechanism 925 also rotates. During the rotation of the gear driving mechanism 925, the engagement features 923 of the gear driving mechanism 925, which are engaged with the engagement features 973 of the ring gear 975, force the ring gear 975 to rotate.

FIG. 10 shows another offline casing string rotation system 1080 (without the drive unit) according to certain example embodiments. Referring to FIGS. 1 through 10, the offline casing string rotation system 1080 of FIG. 10 includes a ring gear 1075 having multiple engagement features 1073 that are evenly distributed along the outer surface of the ring gear 1075. The offline casing string rotation system 1080 also includes a gear driving mechanism 1025 having single continuous engagement feature 1023 that is evenly distributed along a segment of the outer surface of the gear driving mechanism 1025. The gear driving mechanism 1025 in this case is in the form of a worm and the ring gear 1075 is in the form of a worm wheel so that the offline casing string rotation system 1080 has a worm drive configuration.

A shaft 1027 is fixedly coupled to the gear driving mechanism 1025. As the shaft 1027 rotates (caused by a drive unit, not shown in FIG. 10), the gear driving mechanism 1025 also rotates. During the rotation of the gear driving mechanism 1025, the engagement features 1023 of the gear driving mechanism 1025, which are engaged with the engagement features 1073 of the ring gear 1075, force the ring gear 1075 to rotate.

Example embodiments can be used to provide for more complete cementing operations within a wellbore without the use of rig equipment. Example embodiments can be used in land-based or offshore field operations. Example embodiments also provide a number of other benefits. Such other benefits can include, but are not limited to, reduced use of resources, cost savings, increased flexibility, and compliance with applicable industry standards and regulations.

Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope and spirit of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.

Claims

1. An offline casing string rotation system comprising:

a ring gear configured to be coupled to a rotatable mandrel casing hanger, wherein the rotatable mandrel casing hanger is part of a wellhead assembly and is coupled to a top end of a casing string; and

a gear driving assembly moveably coupled to the ring gear, wherein the gear driving assembly, when enabled, causes the gear to rotate the rotatable mandrel casing hanger.

2. The offline casing string rotation system of claim 1, wherein the gear driving assembly comprises a drive unit and a gear driving mechanism coupled to the drive unit.

3. The offline casing string rotation system of claim 2, wherein the gear driving mechanism of the gear driving assembly further comprises a pinion, and wherein the gear comprises a ring.

4. The offline casing string rotation system of claim 2, wherein the gear driving mechanism of the gear driving assembly further comprises a worm, and wherein the gear comprises a worm wheel.

5. The offline casing string rotation system of claim 2, wherein the drive unit operates hydraulically.

6. The offline casing string rotation system of claim 2, wherein the drive unit is motorized.

7. The offline casing string rotation system of claim 1, wherein the gear has a spiral bevel configuration.

8. The offline casing string rotation system of claim 1, further comprising a sensor that measures a rate of rotation of the rotatable mandrel casing hanger has driven the gear driving assembly.

9. The offline casing string rotation system of claim 8, wherein the rate of rotation is at least 5 rotations per minute.

10. The offline casing string rotation system of claim 1, further comprising a cement head support system coupled to a top end of the wellhead assembly, wherein the cement head support system remains stationary as the rotatable mandrel casing hanger rotates.

11. The offline casing string rotation system of claim 1, wherein cement is pumped through a cavity formed by the rotatable mandrel casing hanger and the casing string as the rotatable mandrel casing hanger is rotated.

12. The offline casing string rotation system of claim 1, wherein the ring gear is coupled to the rotatable mandrel casing hanger using a plurality of fastening devices.

13. A method for rotating a casing string, the method comprising:

coupling a ring gear to a rotatable mandrel casing hanger, wherein the rotatable mandrel casing hanger is part of a wellhead assembly and is coupled to a top end of a casing string;

engaging a gear driving mechanism with the ring gear, wherein the gear driving mechanism is part of a gear driving assembly; and

operating a drive unit coupled to the gear driving mechanism, wherein the drive unit, when operating and using the gear driving mechanism and the ring gear, rotates the rotatable mandrel casing hanger.

14. The method of claim 13, further comprising:

pumping cement through a cavity in the rotating mandrel casing hanger and the casing string as rotatable mandrel casing hanger is rotated.

15. The method of claim 13, wherein the gear driving mechanism comprises a pinion and a shaft coupled to the pinion, wherein the pinion engages the ring gear, and wherein the shaft is further coupled to the drive unit.

16. The method of claim 15, wherein the pinion has a first size that is smaller than a second size of the ring gear.

17. The method of claim 13, wherein the drive unit operates hydraulically.

18. A system for cementing a casing string in a wellbore, the system comprising:

a wellhead assembly disposed at an entry point of the wellbore, wherein the wellhead assembly comprises a rotatable mandrel casing hanger coupled to a top end of the casing string;

a cement head coupled to a top end of the wellhead assembly; and

an offline casing string rotation system coupled to the rotatable mandrel casing hanger, wherein the offline casing string rotation system comprises: a ring gear coupled to the rotatable mandrel casing hanger; and a gear driving assembly moveably coupled to the ring gear, wherein the gear driving assembly, when enabled, causes the gear to rotate the rotatable mandrel casing hanger.

19. The system of claim 18, wherein the gear driving assembly comprises a drive unit and a gear driving mechanism coupled to the drive unit.

20. The system of claim 19, wherein the gear driving mechanism comprises a pinion gear and a shaft.