Patent Application
20130292136
The present invention relates to a device and method for the gripping and or handling of tubular members. These tubular members vary widely in size, shape, thickness, function, orientation while in service, and industries served. They can be pipes, steel structures, columns, tubing, casing, culverts, pilings, caissons, pipelines, etc. A non-inclusive list of uses for the present invention includes:
1) A first use is in the construction of oil and gas wells where it is usually necessary to drill and line the well bore with a string of steel pipes commonly known as tubulars, casing, tubing, or generically as oil country tubular goods (“OCTG”).
2) A second use is in the abandonment or decommissioning of oil and gas wells where it is usually necessary to remove the steel pipes commonly known as tubulars, casing, tubing, or generically as oil country tubular goods (“OCTG”), steel structures, pilings, caissons and or pipelines
3) A third use is in anchoring connector systems for offshore drilling establishments. In deepwater drilling activities the use of floating drilling rigs is necessary. These drilling rigs may be in the form of semi-submersibles, spars, drill ships, etc. These drilling rigs must be anchored or tethered to the sea floor to remain in position. To accomplish this, suction anchors are deployed and placed onto the sea floor. Large ropes or chains must then be attached from the drilling rig to these anchors. Anchoring connectors are used to connect the ropes or chains to the anchors via ROV's. These anchoring connectors are far easier to attach in deep water or extreme depth conditions using large shackles or the like.
4) A fourth use is in the recovery of damaged or abandoned pipelines from the sea floor. These connectors provide a means to grip the pipeline while being manipulated by a ROY.
5) A fifth use is in the placement of columns for wind energy turbines.
6) A sixth use is in the erection of structures fabricated from tubular members such as offshore platforms, water towers, etc.
While not limiting in any way the intended use of the present invention, for purposes of description the use of the present invention as it relates to a device and method for facilitating the connection of tubulars used in the oil and gas exploration and extraction industries using a top drive will be presented to illustrate the elements of the present invention. More specifically, the invention will be described as it relates to a device and method for running tubulars into and or out of a well bore.
In the construction of oil or gas wells it is usually necessary to drill and line the well bore with a string of steel pipes commonly known as tubulars, casing, tubing, or generically as oil country tubular goods (“OCTG”). For purposes of this application, such steel pipes shall hereinafter be referred to as “tubular OCTG”. Because of the length of the tubular OCTG required, individual sections of tubular OCTG (tubular members) are typically progressively added to the string (tubular string) as it is lowered into or lifted out of a well from a drilling rig or platform. The, section to be added or removed is restrained from falling into the well by some tubular engagement means, typically a spider or the like, and is lowered into the well to position the threaded pin of the tubular OCTG section adjacent the threaded box of the tubular OCTG in the well bore. The sections are then joined by relative rotation of the sections and the process repeated until such time as the desired total length has been achieved.
It is common practice to use a power tong to torque each connection to a predetermined torque in order to connect the sections of tubular OCTG. This traditional method and equipment types have been used extensively around the world for a period in excess of fifty years. While this method is in daily use it normally requires a large team of specialist personnel along with a plethora of equipment to successfully undertake this task. It is also a very dangerous task with personnel often having to be located on a small platform suspended up to 50 feet from the rotary table or drilling rig floor and the power tong tethered to a steel cable under high loads.
In more recent times, a top drive may be used; this is, a top drive rotational system used for drilling purposes. Where a top drive system is used to make up the connection, the use of a slip type elevator to restrain the section of tubular OCTG to be added may be problematic, due to the configuration of the top drive apparatus on the drilling platform. It is therefore known to make use of an apparatus connected to the top drive, which can be inserted into the interior of or around the exterior of a section of tubular OCTG to be added, and engaged therewith to hold the section in place. Such apparatus may comprise one or more toothed grapple/dies, which may be hydraulically operated to engage an inner or outer surface of the tubular OCTG. While this is an advancement over the traditional approach as it requires substantially less equipment, it does however have serious drawbacks in the form of potential damage it may cause to the outer or inner surface of the tubular OCTG. These grapple/dies also tend to be very sensitive to varying changes in tubular weight and diameters and therefore require a large resource of alternative sizes for each tubular OCTG size or weight to be run.
Secondly, as the grapple/dies tend to bite aggressively into the tubular OCTG and take no account of alignment issues it is possible to load one side of the grapple/dies while running the tubular OCTG into the well bore. The possibility of loading one side of the tubular OCTG can present serious consequences for the integrity of the tubular OCTG and its ability to withstand down-hole pressures in the borehole. This in turn may also result in premature failure of the grapple/dies or impede their ability to act correctly on the tubular OCTG.
Thirdly, as the grapple/dies tend to be suspended on the outside of the member for internal gripping tools with no means of constraint they can become a huge safety issue if the rotational drive is engaged whilst the probe is not inside the tubular OCTG. The centrifugal forces cause the grapple/dies to separate from the tool member, causing them to become entangled in the steel framework of the rig and potentially becoming dangerous objects falling from the derrick structure.
Fourthly, traditional methods of tool design permits the slip assemblies, bodies or inserts to potentially friction bond or become adhered to each other under heavy load conditions. This factor is due to the static frictional forces increasing; thereby displacing the lubricants between the sliding member surfaces. If these slip assemblies, bodies or inserts become frictionally adhered, this can cause serious problems, especially in a well control situation. It can cause the tubular OCTG or the slip assemblies, bodies or inserts to require to be mechanically separated by means of a cutting torch or other means.
Lastly in more recent designs the grapple/dies portion has been replaced by the adoption of ball and taper or rolling element and taper technology originally designed for anchor handling applications where a static or dynamic axial load is applied. In order to better understand the terminology and advantages of the present invention the definitions of a ball and rolling support are:
In mooring applications for offshore floating structures chain is widely used, usually as part of a system combining chain and rope, be it fiber or wire. Multiple connectors and chain are favored for mooring systems for several reasons:
It is rugged and less prone to damage than wire or fiber rope when used with topsides, catenary, or seabed equipment. It is also easy to handle and requires only standard topsides tensioning equipment
While this method of multiple connectors or anchor stations has been successful in mooring connectors where a failure of one connector will most likely not have a serious impact on the other connectors and repairs can be expedited. Design safety factors for mooring connectors and or mooring chains are substantially lower than the International Standard ISO 13535 for Petroleum and natural gas industries—Drilling and production equipment—Hoisting equipment. When it comes to handling tubulars OCTG's where a single connector is used the failure of this single connector has the potential for catastrophic consequences.
A first disadvantage of previous attempts is in the design of the member containing the inclined or tapered ramps which include areas of deeper than necessary pockets as well as sharp corners. These pockets are used for assembly purposes in some previous attempts and for locating spring biasing devices in others. These pockets decrease the minimum cross sectional area. The minimum cross sectional area of the member containing the inclined ramps is a critical factor in determining the Safe Working Load rating and or capabilities for the gripping device. The International standard ISO 13535 for Petroleum and natural gas industries—Drilling and production equipment—Hoisting equipment requires that all hoisting equipment furnished under this International Standard shall be rated in accordance with a specific load rating based on the design safety factor. This is especially important for internal gripping devices where the device outside diameter is dictated by the internal diameter of the tubular OCTG to be run or pulled. Thus, the main cross sectional area of the load bearing member is vitally important and must be maximized by all means possible.
The design safety factor is specified as a multiplication formula for hoisting equipment whereby the specified minimum yield strength of the materials chosen must be tested between two and a quarter (2 ¼) and three (3) times the safe working load, then checked for functionality, fit and fully inspected for signs of failure. Thus, it is evident that in order to comply with the Safe Working Load Rating and Design Safety Factors hoisting tools must have the cross sectional area maximized to achieve the high load carrying capacities required of them.
A second disadvantage of previous attempts is that they were ineffective in providing the rotational torque capacity required for the make-up or break-out of said tubular OCTG. This is due to the self-engaging, spring biased, or gravity biased balls or rolling elements of current designs. Some embodiments of previous attempts utilize springs on individual balls or rolling elements to urge them down the inclined surface toward the shallow end causing them to protrude from the cage. This method of energizing the balls or rolling elements is ineffective in applying an adequate amount of preload force on the balls or rolling elements to create an indentation of sufficient size and depth to apply the required torque without slipping. These designs do not allow the operator the ability to hydraulically, pneumatically, or mechanically control these preload forces to create the required indentations for applying torque.
A third disadvantage of this previous attempts is in the design of the openings or slots and its role in applying torque. Previous attempts cage housing openings make no attempt to aid in the application of torque. It will be shown in the accompanying drawings that the design of the cage housing openings of the invention presented here make accommodations for aiding in the transmission of torque. The cage housing openings contain large surface areas on the flat sides to contact against the sides of the rolling supports for torque transmission. This cage housing can also be splined, keyed, or otherwise affixed to the member containing the inclined surfaces to allow relative axial movement while disallowing relative rotational movement. This feature allows torque to be transmitted from the member having the inclined surfaces, through the cage and rolling supports, to the tubular.
A fourth disadvantage of this previous attempts is the use of elongated slots where the length of the slot is substantially longer than the diameter of the ball or rolling element. When disengaging a gripping device utilizing these elongated slots, the cage housing must travel axially an excessive distance before the slot comes into contact with the ball or rolling element then must continue to travel axially to urge the ball or rolling elements up the inclined surface toward the deep end of the pocket and thus released position.
A fifth disadvantage of these elongated slots is the large cavity created between the elongated slots and the inclined surfaces. This cavity may become filled with debris or other materials than can inhibit or prevent the function of the gripping device.
A sixth disadvantage of the elongated slot design is that the slot must contain a means of retaining the ball or rolling element along the longer sides of the slot because the ball or rolling element must be allowed to travel the entire length of the slot. This is generally accomplished by having the width of the slot narrower than the diameter or width of the ball or rolling element. This aspect of the design prevents the sides or edges of a rolling element to protrude from the cage housing which limits the options for the shape of the rolling element. It is important to have the ability to change or modify the shape of the rolling elements to accommodate varying applications. The shape of the rolling element can also limit the range of outer or inner surface diameters which can be gripped with a given gripping device configuration.
A seventh disadvantage of the elongated slots is amount of material that is removed from the cage housing diminishing the structural integrity of the cage housing. Tools and equipment manufactured for service on a drilling rig must be very robust as they operate in extreme conditions. Transporting tools to or from a drilling rig, loading, and unloading of these tools, especially on an offshore location, as well as handling of these tools can create damages. Thus tool designs must account for these conditions of service.
A eighth disadvantage of previous attempts is the means of disengaging or releasing an internal gripping device during entry into a tubular whereby frictional forces acting upon the outer surface of the cage housing imposed from the internal surface of the tubular act to urge the cage housing in a direction such that the rolling elements move toward the deep end of the inclined surfaces, thus released position. This previous attempts design requires these frictional forces to function properly. This “dragging” of the cage housing produces wear on the cage housing as well as the internal surface of the tubular. This dragging can also cause damage to the internal tubular threads. Again, it will be evident from the accompanying drawings and descriptions that the present invention is superior in that it provides a hydraulic, pneumatic, or mechanical means of retracting or releasing the gripping device prior to entering a tubular. It is also a feature of this invention that the rolling supports are not allowed to fully retract into the cage housing. In a fully retracted position, the rolling supports remain partially protruded from the cage housing. This allows the rolling supports to act as rolling bearings between the cage housing and tubular surface aiding in the entering and or exiting of a tubular.
A ninth disadvantage of previous attempts is in the design of the member containing the inclined or tapered ramps which include areas of deeper than necessary pockets as well as sharp corners. It is known that sharp edges or corners should be eliminated where possible to remove stress concentration areas as well as areas increasing the potential for cracking. These sharp corners also create areas prone to corrosion and or rusting.
A tenth disadvantage of previous attempts is in the use of multiple components such as small springs, plungers, inserts, biasing devices, etc which are all made unnecessary by the embodiments of the present invention. All of these components must be held in place via means such as press fitting, adhesives, threaded fasteners, etc. which all initiate the potential for failures. It is well known that as the number of parts is increased for a single mechanical device so does the odds of failure. The corresponding machining or manufacturing processes for these components is greatly complicated by the use of these components. The complexity and tight tolerances required to successfully manufacture these components substantially increases the overall cost of the gripping device.
An eleventh disadvantage of previous attempts again in the use of multiple components such as small springs, plungers, inserts, biasing devices, etc is that should any of these small components become loose or free from constraint, they can potentially fall into the wellbore. This potential is very high due to the jarring and shock loads the gripping device will experience in service as well as transport. These shock loads can loosen threaded fasteners or other means of retention. Also, heat and or extreme cold can affect retention means such as adhesives, press fit and interference fit tolerances. Should any of these components become free from constraint, the elongated slots will allow these items to depart from the assembly, thereby becoming major safety hazards with the potential for serious damage to personnel or structures from flying debris. Materials or items which unintentionally fall into the wellbore create an array of very costly problems.
A twelfth disadvantage of the previous attempts utilizing the aforementioned inserts which are press fit or otherwise attached to the member containing the inclined surfaces is in the non destructive testing of these components after each use in the field.
It is well known in the oilfield industry that after each use, all load carrying tools must be completely disassembled, cleaned, and inspected for cracks, wear, damages, or anything else that may prevent a tool from functioning properly or possibly failing in service. Components which are press fit or adhered using adhesives are generally very difficult or impossible to remove for inspection purposes. This means that these parts will likely not be removed thereby possibly hiding a crack or damage. If a threaded fastener is used, these threads create stress risers and areas for corrosion to begin.
The intention of the present invention is to offer a much improved apparatus and method of running tubular OCTG into or out of a borehole vastly improving the safety, efficiency and torque capability without the shortfalls in the tools available today.
A device and method has been invented for gripping and or handling tubular members. For purposes of clarity, the embodiment of the present invention as it relates to the handling of OCTG will be described. The inventive device is connectable to a top drive and can be used to grip the tubular OCTG from the inside or the outside. The system comprises a top drive, a tubular OCTG running assembly, elevator links, transfer elevators, tubular sealing element, and mud valve.
The operator can remotely manipulate the elevator links to extend or retract the transfer elevators to pick up and position a tubular OCTG above the tubular OCTG already secured in the rotary table on the drill floor. This function is normally achieved using a manually operated single joint elevator; however the present invention has incorporated a hydraulic transfer elevator complete with safety interlock thereby reducing the need to manually position or function the transfer elevator making the operation much safer and more operationally efficient. The operator can then engage a probe and activate a hydraulic or pneumatic actuator causing the inventive gripper assembly to grip the tubular OCTG, and then use the rotational capability of the top drive to remotely couple the two joints of tubular OCTG together.
According to a first aspect of the present invention, there is provided a tubular OCTG running assembly for running tubular OCTG into and/or out of the well bore, the assembly comprising a probe engageable within the tubular OCTG, wherein the probe comprises an inner member having an outer surface with a plurality of ramped or inclined surfaces and an outer cage surrounding the inner member having a plurality of openings to captively constrain rolling supports with or without a central spindle. The openings of the outer member are aligned with the ramped or inclined surfaces of the inner member and are axially movable to cause the rolling supports with or without a central spindle to climb and descend the ramped or inclined surfaces thus, respectively to retract within and protrude from said openings and, when protruding, to bear upon the inner surface of the tubular OCTG to lock the probe and receiving tubular OCTG in engagement.
According to a second aspect of the present invention, there is provided a tubular OCTG running assembly for running tubular OCTG into and/or out of the well bore, the assembly comprising a housing assembly engageable with the external surface of the tubular OCTG, wherein the housing assembly comprises an outer member having an inner surface with a plurality of ramped or inclined surfaces and a cage within the outer member having a plurality of openings to captively constrain the rolling supports with or without a central spindle. The openings of the inner member are aligned with the ramped or inclined surfaces of the outer member and are axially movable to cause the rolling supports with or without a central spindle to climb and descend the ramped or inclined surfaces thus, respectively to protrude from and retract within said openings and, when protruding, to bear upon the outer surface of the tubular OCTG to lock the probe and receiving tubular OCTG in engagement.
The probe or external latching assembly farther comprises a hydraulic, pneumatic or mechanical actuator having a sleeve that is in connectable engagement with the cage housing (member with the openings), and when activated, will cause the cage housing to travel axially relative to the movement of the member with the ramped or inclined surfaces, thus providing a means of controlling the placement of the rolling supports with or without a central spindle relative to the ramped or inclined surfaces, therein locking or unlocking the probe or external latching assembly in place prior to applying a rotational force, lifting action or lowering action or both upon the tubular OCTG. The contact forces between the rolling supports with or without a central spindle and the surface of the tubular OCTG can be controlled such that necessary indentations are produced on the tubular OCTG to provide for the required torque value.
The surface of the rolling supports with or without a central spindle can be hemispherical or can be of any other surface profile such as nodular, sinusoidal, waveform, etc. The surface finish or texture can be smooth, coated with a grit type material, toothed such as conventional inserts (could possibly look like a carbide burr), or a combination of these. The hemisphere profiles could be shaped so that they extend beyond the cage housing more than the hemispheric diameter as is with current ball and taper technology which is extremely limited. They can extend out any desired distance allowing the tool to work for a larger range of sizes and or weights.
One major advantage of this method of engagement of the rolling supports with or without a central spindle against the tubular OCTG is that this method provides for maximum displacement of load without causing damage to the inner surface of the tubular OCTG. Damage to or scarring of the inner or outer face of the tubular OCTG can cause premature failure of the tubular OCTG resulting in the requirement to undertake expensive remediation work on the well bore. Standard dies, grapple/dies, inserts, etc. tend to scar the tubulars in both longitudinal and circumferential directions, placing stress concentration areas as well as crevices for corrosion to take place. The advantage of the rolling supports with or without a central spindle engagement mechanism is that they produce smooth indentations which do not create areas of increased corrosion or stress concentrations. The areas of indentation are actually work hardened thus they are mechanically stronger than the remaining tubular material. Thus, this means of engagement enhances the mechanical properties of the tubular rather than degrading the mechanical properties.
According to a third aspect of the present invention, there is provided a remotely operated elevator assembly for facilitating the transfer of a tubular OCTG from the V-door of a drilling rig to the vertical position and thereby allowing the tubular OCTG to be stabbed into a similar tubular OCTG located in the slip assembly located in or on the drill floor for the running or pulling of tubular OCTG into and/or out of the well bore. The elevator assembly comprises a set of telescoping transfer elevator links attached to the tubular running assembly of the present invention connected to the top drive system or drilling hook on a non-top-drive fitted rig, whereby the telescoping transfer elevator links can be extended to facilitate engagement of the tubular OCTG at the V-door and then retracted to bring the tubular OCTG into a position to be raised to a position ready for stabbing of the tubular OCTG into a similar tubular OCTG located in the slip assembly located in or on the drill floor. The elevator assembly may also have an elevator link tilt assembly comprising two or more hydraulic actuators, wherein the link tilt assembly is coupled to the telescoping transfer elevator links such that the extension or retraction of the hydraulic actuators can pivot the telescoping transfer elevator links about a point located on a horizontal axis; providing a secondary means of positioning the transfer elevators to facilitate transfer of the tubular OCTG into the stabbing position for make-up.
The tubular running assembly may further be provided with a positive locking means to maintain the rolling supports with or without a central spindle in engagement with a tubular OCTG should the make-up assembly otherwise fail. The positive locking means may be provided in conjunction with axially angled faces, and/or in conjunction with circumferentially angled faces. The positive locking means may comprise, for example, a spring or hydraulic safety interlock system.
In addition to gripping, rotating, anchoring, lifting and lower the tubular OCTG, another function of the tubular running assembly is to transmit the circulation of drilling fluid or mud through the tubular OCTG. In order to pump drilling fluids or mud, a seal must be established between the tubular OCTG and the tubular running assembly of the present invention. In use, the tubular running assembly will be connected to a top drive via a threaded connection at its upper end, or to a non-top-drive rig via a pup joint latched into an elevator. Both systems have available a means of connecting to a circulating system that will permit the tubular being handled to be filled or circulated at any time during the running operation. In preferred embodiments, the members of the tubular running assembly are equipped with a through bore to permit tubular fill-up and circulation to take place at any time.
There may also be provided a packer cup with a sealing element, preferably comprising an elastomeric element or layer over a steel body. The sealing element of the packer cup is self energizing or pressure activated through a port or chamber located in the inner mandrel, which forces the sealing element against the walls of the tubular OCTG, thereby forming a seal to allow mud or drilling fluid to be pumped through the tubular OCTG assembly.
The present invention further comprises a wireless communication control system that is able to manipulate the telescoping transfer elevator links, link tilts, and other elements of all aspects of the present invention. The control system of the present invention is able to open and close the transfer elevators, retract and extend the telescoping transfer elevator links, the secondary link tilt, control and measure the application of torque and turns and may also stop the rotation of the make-up assembly of the present invention at a pre-determined torque point utilizing either a wireless communication safety system or a system of hydraulic or pneumatic control line umbilicals. The wireless communication safety control system can also be used in other applications to measure and control torque, applied loads such as string weight and/or have the ability to dump torque or applied load at a predetermined point. The wireless communication safety system may also be coupled conventionally using a series of cables should the use of wireless communication be restricted.
The safety control system is also able to set and unset the hydraulic actuator used to hydraulically manipulate the cage housing of the tubular engagement apparatus causing the rolling supports with or without a central spindle to contact the tubular OCTG to facilitate handling and make-up or breakout of the tubular OCTG threaded connection. The safety control system is also able to monitor feedback loops that include sensors or monitors on the elements of the present invention. For example, sensors of the safety control system of the present invention monitor the open and close status of the transfer elevator, the status of the hydraulic, pneumatic and or mechanical actuator and thereby the position of the rolling supports with or without a central spindle. The safety control system is design rated and or certified for use in a hazardous working environment. Communication with the processor of the safety control system can be accomplished through a wireless communications link.
The tubular running assembly may further comprise a lower member with a ramp or inclined surface guide shoe or a bull-nose centralizer with a ramp or inclined surface high density urethane, polymer coated, or composite section sized to suit the tubular OCTG being run, to facilitate easy stabbing of the apparatus into the tubular OCTG, attached to the bottom of the inner member to further protect the thread and sealing areas of the tubular OCTG to be coupled together. The lower member farther comprises a valve to prevent mud discharge onto the drill floor when the mud pumps are disengaged and the apparatus is removed from the tubular OCTG. The lower member can also be fitted with singular or multiple two-way acting check valves to facilitate reverse circulation or a solid member if necessary.
It is an object of this invention to provide a tubular running assembly for connection to a top drive for running individual or multiple tubular OCTG into and/or out of a well bore, and allowing the operator to make-up or breakout a tubular OCTG, wherein the tubular engagement apparatus comprises a series of inner and outer members or housings, one of which has an array of ramped surfaces while the other comprises a series of openings, with a plurality of rolling supports with or without a central spindle captively located between the inner and outer members, wherein relative axial movement of the members or cage housing acts to urge the rolling supports with or without a central spindle to protrude radially through the openings in the cage housing thus engaging the tubular OCTG. It is further intended that the gripping principal may be used for internal or external gripping. It is further intended that the rolling supports with or without a central spindle and their respective ramped or inclined surfaces may be disposed randomly about the tubular engagement apparatus or in longitudinally spaced rows where the rolling supports with or without a central spindle of each row are offset laterally with respect to those of the next succeeding row.
It is a further object of this invention to provide a tubular running assembly for handling a tubular member, making up or breaking out of threaded connections between the tubular member and another tubular member or tubular string, and the handling of the tubular string into or out of a wellbore, comprising a tubular engagement apparatus connectable to the driveshaft of a top drive, power swivel, or the like, the tubular engagement apparatus having rolling supports with or without a central spindle and a ramped or inclined surface assembly and an actuator wherein the rolling supports assembly consist of inner and outer members, one member containing an array of ramped or inclined surfaces while the other member comprises a tube with a plurality of openings which retain the rolling supports with or without a central spindle; wherein relative axial movement between the inner and outer members of the rolling supports with or without a central spindle acts to urge the rolling supports with or without a central spindle up or down the ramped or inclined surfaces to radially protrude or retract rolling supports with or without a central spindle through the openings in the tube member, thus engaging or disengaging the tubular member; wherein the tubular engagement apparatus is energized and de-energized by powered mechanical means provided by the hydraulic, pneumatic, mechanical or the like actuator, whereby the rolling supports with or without a central spindle are forced up or down the ramped or inclined surfaces of the drive member thereby causing the rolling supports with or without a central spindle to come into contact with or retract from the surface of the tubular member; and wherein rotation of the driveshaft of a top drive, power swivel, or the like produces a corresponding rotation in the tubular member or tubular string via engagement of the rolling supports, whereby there is minimal relative rotation between the tubular engagement assembly and the tubular member or tubular string.
The inventive tubular running assembly may also be connected to a power swivel or suspended under a traditional Kelly in the event that the drilling rig does not have a top drive installed and/or on a hydraulic work-over rig or snubbing unit. In the latter application the power swivel may be installed into a hydraulic or pneumatically controlled frame to lift and lower the power swivel and tubular running assembly of the present invention into and out of the tubular OCTG and thereby the well bore.
It is a further object of this invention that the tubular running assembly comprise a hydraulic, pneumatic, mechanical or the like actuator, that when energized will cause the cage housing to travel axially relative to the movement of the member with the ramped or inclined surfaces thus providing a means of controlling the placement of the rolling supports with or without a central spindle relative to the member containing the ramped or inclined surfaces therein locking the probe in place prior or external latching assembly to applying a rotational force, lifting or lowering action upon the tubular OCTG.
It is further intended that the tubular running assembly be provided with a through bore to allow the transmission of drilling fluids or mud for the purpose of filling or circulation of the tubular OCTG while running into the well bore and further comprise a lower packer cup on the lower member section of the make-up assembly which is self energizing or pressure activated through a port or chamber located in the inner mandrel thereby fanning a seal to allow drilling fluid or mud to be pumped into the tubular OCTG and/or well bore.
It is an object of this invention that the tubular running assembly further comprise an elevator assembly with elevator links and transfer elevators which can be remotely manipulated to extend or retract the transfer elevators to pick up and position a tubular OCTG above the tubular OCTG already secured in the rotary table on the drill floor wherein the operator can then engage the make-up assembly to energize the rolling supports and use the rotational capability of the top drive to remotely couple the two tubular OCTG together.
It is a further object of this invention that the elevator assembly comprise a set of links used to position the tubular OCTG from a mostly horizontal position to the vertical position wherein said links each contain a single and or multi stage hydraulic or pneumatic cylinder contained within the body of the links or mounted externally allowing the operator to extend the links into the correct position to accept the tubular OCTG in the transfer or lifting elevators.
It is a further object of this invention that the hydraulic or pneumatic cylinders may be coupled to a weight compensation control system whereby the activation of the weight compensation system will provide for the tubular OCTG to be lowered in a controlled fashion into the tubular OCTG already secured in the rotary table on the drill floor and utilizing the weight compensation system will effectively give the tubular OCTG zero weight in gravity and protect the threads of the tubular OCTG during stabbing operations, for make-up or breakout operations.
It is a further object of this invention that the weight compensation control system can be a separate system installed above the tubular running assembly actuator and below the top drive whereby the activation of the weight compensation system will provide for the tubular OCTG to be lowered in a controlled fashion into the tubular OCTG already secured in the rotary table on the drill floor and utilizing the weight compensation system will effectively give the tubular OCTG zero weight in gravity and protect the threads of the tubular OCTG during stabbing operations, for make-up or breakout operations.
It is a further object of the invention to provide a method of running tubular OCTG into and/or out of a well bore, comprising the steps of: locating a tubular OCTG and extending links and transfer elevators around the tubular OCTG; latching transfer elevator around tubular OCTG; moving a top drive with a tubular running assembly in an upward movement causing the captured or retained tubular OCTG into a vertical position above a tubular OCTG already secured in the rotary table on the drill floor; activation of the weight compensation system to lower the tubular OCTG in a controlled fashion into the aforementioned tubular OCTG already secured in the rotary table; engage the threads of the upper tubular OCTG in the threads of the tubular OCTG already secured in the rotary table on the drill floor; activate the hydraulic, pneumatic, mechanical or the like actuator, into the release position producing relative movement of the members causing the rolling supports with or without a central spindle to retract radially through openings in the tube; lowering the tubular running assembly onto or into the tubular OCTG; activate the hydraulic, pneumatic, mechanical or the like actuator into the latch position producing relative movement of the members causing the rolling supports with or without a central spindle to protrude radially through openings in the tube; once the rolling supports with or without a central spindle are engaged on the inner or outer wall of the tubular OCTG, rotate the top drive mechanism to cause the upper tubular OCTG threads to engage correctly with the mating threads of the tubular OCTG already secured in the rotary table on the drill floor and thereby connecting both tubular OCTG into one continuous member; lifting the tubular OCTG members in an upward direction by the tubular running assembly connected to the top drive while unsetting the slip mechanism of the retaining device in the rotary table to allow the joined tubular OCTG to be lowered into the well bore. By reversing the process the tubular OCTG members can be removed from a well bore if desired.
It is further intended that the surface of rolling supports with or without a central spindle may be: smooth, smooth and hardened, coated with a grit type material, toothed such as conventional inserts and dies, toothed and grit coated, or a multitude or combination thereof. The rolling supports with or without a central spindle block surface may be of any shape or profile including: smooth, curved, flat, hemispherical, nodular, lumpy, sinusoidal, waveform, etc., and any combination thereof. The hemispheres or other surface profiles on the rolling supports with or without a central spindle can either be smooth, coated with a grit type material, can include some type of tooth profile such as conventional dies, or any combination thereof. The hemispherical profiles of the rolling supports with or without a central spindle can be shaped so that they extend beyond the tube member more than is possible with current ball and taper technology. They can extend out any desired distance, thereby allowing the tool to work for a larger range of sizes and or weights. The backing surfaces and cage provide far more contact surface area between the rolling supports with or without a central spindle backing surface and member ramped or inclined surface ramp than balls. The rolling supports with or without a central spindle also provide more surface area on their edges for the application of torque than do balls. Again, balls create a point loading on the sides of the ramped or inclined surface slots on the member with the potential for indentation. The rolling supports with or without a central spindle greatly reduce this potential for member damage. The surfaces of the rolling supports with or without a central spindle and or the sliding mating surface of the member can be coated with a friction reduction material, plating or process such as Teflon, Xylan, plain bearing or self lubricating materials such as an acetal filled bronze, chrome plating, hard chrome plating, electroless nickel, etc. The rolling supports are constrained within a housing, such that they cannot be removed without complete disassembly of the tool. This becomes important should the assembly be rotated in free space (such as above a rig floor in the derrick), the rolling supports with or without a central spindle cannot become projectiles. The rolling supports with or without a central spindle technology including the hemispherical or nodular surface features may also be used as inserts, dies or grapple/dies for other tubular running or gripping tools such as tongs, spiders, elevators, hand-slips safety clamps, fishing tools, sub surface tools, whipstocks or packer type assemblies etc.
These and other aspects of the present invention will now be described by way of example only and with reference to the accompanying drawings, in which:
In
The tubular engagement apparatus configured to grip the interior of a tubular comprises an inner tubular member 7 shown in
The inner member 7 may be of circular cross section having the outer cage 3 concentrically disposed around it.
The inner member 7 and the cage 3 may be arranged for longitudinal movement one with respect to the other.
The inner member 7 and the outer cage 3 may be splined or keyed to one another thereby allowing longitudinal relative movement but disallowing rotational movement there between.
The cage may be an outer cage 3 having an array of openings 4, through which the respective rolling supports with or without a central spindle 9 may partially protrude. The cage is substantially a tube, but may also be split into two or more parts or may be manufactured in more than one component, plate, etc. for assembly purposes.
The tubular engagement apparatus can also be configured to grip the exterior surface of a tubular. This exterior tubular engagement apparatus operates just as the aforementioned internal tubular engagement apparatus but is configured such that the cage member and the inclined surfaces are on the interior of the tubular engagement apparatus.
An embodiment of the present invention will now be described, by way of example only with reference to the accompanying drawings numbered as
It will be apparent that many other changes may be made to the illustrative embodiments, while falling within the scope of the invention and it is intended that all such changes can be covered by the claims appended hereto.
Although the disclosed embodiments have been described in detail, it should be understood that various changes, substitutions and alterations can be made to the embodiments without departing from their spirit and scope. Other technical advantages of the present invention will be readily apparent to one skilled in the art from the following figures, drawings, descriptions and claims.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US12/21820 | 1/19/2012 | WO | 00 | 7/19/2013 |
| Number | Date | Country | |
|---|---|---|---|
| 61435157 | Jan 2011 | US |
