Patent Grant
10570677
This invention relates to subsurface drilling. Example applications are drilling for petroleum and/or natural gas. The application relates to apparatus and methods for handling tubular strings (e.g. drill string sections, casing or the like).
Subsurface drilling uses a drill string made up of a series of sections that are connected to one another end-to-end. The sections that couple together longitudinally to make a drill string may be called various names including “drill string sections”, “joints”, “tubulars”, “drill pipes”, or “drill collars”. Most commonly, the sections each have a pin end and a box end with complementary threads that are screwed together. The threads are commonly API standard threads.
When a well is being drilled, a drill bit is provided at the downhole end of the drill string. The drill bit drills a borehole that is somewhat larger in diameter than the drill string such that there is an annulus surrounding the drill string in the borehole. As the well is drilled, drilling fluid is pumped down through the drill string to the drill bit where it exits and returns to the surface through the annulus. The drilling fluid serves to counteract downhole pressures and keep the wellbore open. The drilling fluid also carries rock and other cuttings to the surface. As drilling progresses and the well bore gets deeper, new drill string segments are added at the uphole end of the drill string.
The first (farthest downhole) sections of a drill string are typically made up of heavy drill collars which, through their weight, apply pressure to the drill bit. This part of the drill string is typically called a bottom hole assembly or “BHA”. Above the BHA, the drill string sections may be lighter in weight.
Drilling is typically done using a drill rig. The drill rig includes equipment for rotating the drill string. In some cases, this equipment comprises a rotary table. In other cases, this equipment comprises a top drive. In either case, at the drill rig, as drilling progresses, new sections are added to the top of the drill string. This is done using equipment on the drill rig. Adding a new section typically involves supporting the drill string, uncoupling the top end of the drill string from the kelly or top drive that was supporting it, coupling a new section to the top end of the drill string, connecting the uphole end of the new section to the kelly or top drive and resuming drilling. Typically the weight of the drill string is carried by slips on the drill rig floor while a new section is being added to the drill string.
Periodically, as drilling progresses, it is usually necessary to retrieve the drill string from the well bore. This may be required, for example, to replace the drill bit if the drill bit is becoming worn. This also may be required in cases where there is downhole equipment of some kind that needs to be retrieved to the surface for servicing. The process of bringing a drill string back to the surface and returning the drill string into a partially completed well bore is called “tripping”. Since well bores may be many thousands of feet deep, tripping may take a long time to complete. Operating a drill rig is very expensive. Consequently, tripping can contribute large costs.
Some systems have been proposed for making tripping a drill string more efficient. These include U.S. Pat. No. 8,844,616 and US20140124218. These systems have various disadvantages. Practical alternatives to these systems are required.
There is a general need for ways to improve the efficiency of subsurface drilling. There is a particular need to reduce the time taken to trip a drill string.
This invention has a number of aspects. While these aspects may be practiced in various combinations with one another, a number of these aspects can be applied individually. By way of non-limiting example, some aspects described herein include:
One aspect provides methods for tripping a drill string or other tubular string (casing is another example of a tubular string). The tubular string may comprise coupled-together separate sections or may be a continuous tubular string (e.g. a string of drill pipes welded end-to end of arbitrary length). A method for tripping a tubular string may comprise providing a circulating member supporting a plurality of elevators, moving the circulating member to cause the elevators to circulate along a closed path. While moving the circulating member, a first one of the elevators may engage the tubular string at a first location and a second one of the elevators may engage the tubular string at a second location. The first and second locations optionally correspond to first and second tool joints of the drill string. The weight of the drill string is initially supported on the first one of the elevators and is then transferred to the second one of the elevators. The method may optionally comprise additional steps. Various additional steps are described below. One skilled in the art would understand that the steps below can be added to the methods for tripping a drill string in any logical combination or order.
In some embodiments, after transferring the weight of the drill string to the second one of the elevators, a connection of a drill string section containing the first tool joint is unmade from a drill string section containing the second tool joint. Unmaking the connection may comprise gripping the second tool joint with a backup jaw, gripping the drill string section with a rotary jaw and turning the rotary jaw relative to the backup jaw. Unmaking the connection may be performed while moving the circulating member such that the second one of the elevators lifts the drill string while the connection is unmade.
In some embodiments, after unmaking the connection, transferring the tubular string section to a pipe handling system. In some embodiments, the drill string section may be carried to a backside of the path and, on the backside of the path, the drill string section may be transferred to a pipe handling system. Transferring the drill string section to the pipe handling system may comprise lowering a bottom end of the drill string section onto an end stop of the pipe handling system and allowing relative motion of the first one of the elevators and the end stop to lift the first tool joint relative to the first one of the elevators. While lowering the bottom end of the drill string section onto the end stop, the end stop may be moving in a generally downward direction.
In some embodiments, before transferring the weight of the drill string to the second one of the elevators, a connection of a drill string section containing the first tool joint is made to a drill string section containing the second tool joint. The drill string section containing the second tool joint may be delivered from below the circulating member. Alternatively, the drill string section containing the second tool joint may be delivered from circulating member. Making the connection may be performed while moving the circulating member such that the first one of the elevators lowers the drill string while the connection is being made.
In some embodiments, a make break unit is carried together with each one of the elevators and unmaking the connection is performed by the make break unit corresponding to the second one of the elevators.
In some embodiments, while supporting the drill string on the first one of the plurality of elevators, a top drive is coupled to the circulating member and a quill of the top drive is coupled to a coupling at an uphole end of the drill string. With the quill of the top drive coupled to the uphole end of the drill string, the top drive is operated or held to drive the drill string to advance the borehole while moving the circulating member (the borehole may be advanced without rotating the drill string if a downhole motor is provided to drive a drill bit). The weight of the drill string is transferred to the second one of the plurality of elevators, the quill of the top drive is uncoupled from the drill string and the top drive is uncoupled from the circulating member. Optionally, while supporting the drill string on the first one of the plurality of elevators the circulating member may be operated to move the drill string in the borehole. The movement may comprise reciprocation of the drill string. In some embodiments, the top drive is connected to the circulating member by attaching it to the elevator or crosshead.
In some embodiments, transferring the weight of the drill string onto the second one of the elevators may comprise moving the elevators relative to one another. The elevators may be suspended from pivotal couplings that connect the elevators to the circulating member and engaging the first tool joint of the drill string with a first one of the elevators may comprise pivoting the first one of the elevators about its point of connection to the circulating member. While transferring the weight of the drill string to the second one of the elevators the drill string longitudinally may move at a speed in the range of 0 to 5 feet/second (approximately 0 to 1½ m/s).
In some embodiments, before unmaking the connection, the drill string may be passed through a cavity of a mud can. The mud can may be located substantially to surround the connection. It is not necessary that the mud can be split, the cavity of the mud can may be defined by a tubular body. Drilling fluid that escapes when the connection is unmade may be removed from the cavity of the mud can by gravity drainage, suction, pumping or some combination thereof. In some embodiments, before unmaking the connection a first seal is inflated around a circumference of the first drill string section and/or a second seal is inflated around a circumference of the second drill string section. After unmaking the connection, the mud can may be moved past the second one of the plurality of elevators without removing the mud can from the tubular string. In some embodiments, this comprises tilting the second one of the elevators. In other embodiments, this comprises passing the mud can through an opening in the second one of the plurality of elevators, where the opening is large enough to allow the mud can to pass through the elevator without removing the mud can from the drill string.
In some embodiments, the circulating member may comprise a pair of parallel chain loops supported for circulation on a tower. Each of the pair of parallel chain loops may be driven with a corresponding drive sprocket.
Another aspect of the invention provides drilling apparatuses. A drilling apparatus may comprise a tower, a pair of parallel chain loops supported for circulation on the tower, a drive connected to circulate the chain loops, a plurality of crossheads connected pivotally between the chain loops at spaced-apart locations along the chain loops, each of the crossheads supporting an elevator for a drill string, and one or more actuators coupled to adjust an elevation of each elevator relative to the chain loops. The apparatus may optionally comprise additional features. Various additional features are described below. One skilled in the art would understand that the features below can be added to the drilling apparatuses in any logical combination.
In some embodiments, the chain loops are supported by a pair of top sprockets at a top end of a path followed by the chain loops and the tower is constructed to provide an opening between the top sprockets, the opening extending vertically from a location above the tops of the top sprockets by a distance sufficient to pass a tubular string section suspended by the elevator of one of the crossheads while a point of attachment of the crosshead to the chain loops is passing over the top sprockets. The opening may extend vertically by a distance of at least 10 meters downward from top edges of the top sprockets. In some embodiments the opening extends for 20 or more meters below tops of the top sprockets.
In some embodiments, each of the crossheads comprises first and second pivotal couplings respectively coupled to the first and second chain loops and a platform suspended from the first and second pivotal couplings, the platform having an opening extending from an edge of the platform to a location directly below a pivot axis of the couplings. The platform may be coupled to the pivotal couplings by extendable beams that are attached to the platform and are slidably coupled to the pivotal couplings. For example, each side of the platform may be coupled to a corresponding one of the pivotal couplings by a pair of spaced-apart linear rails or by a telescoping beam. One of the one or more actuators may be located between the linear rails of each of the pairs of linear rails. The actuators may act on bridges coupling the linear rails of each of the pairs of linear rails to selectively raise the platform toward, or lower the platform away, from the pivot axis of the couplings. The linear rails may extend through guide tubes attached to the pivotal couplings and the guide tubes include spaced-apart bushings or bearings.
In some embodiments, each of the chain loops comprises opposing longitudinally-extending plates coupled by transversely-extending pins and the pivotal couplings each comprise one of the pins being a hollow pin having a bore extending longitudinally through the pin. In some embodiments a spherical bearing is located in the bore between the plates, and a spigot coupled to the pin by the spherical bearing. A passage may extend through the spigot in at least one of the pivotal couplings, the passage being connected to supply power to one or more devices supported on the cross heads. In some embodiments, the passage exits on an axial centerline of the spigot and the drilling apparatus comprises a rotary coupling connected to fluidly couple the passage to a hydraulic conduit extending along the chain. The pins preferably comprise rollers.
In some embodiments, the drilling apparatus comprises an actuator connected to tilt the crosshead about the pivot axis of the pivotal couplings.
In some embodiments, the drilling apparatus comprises a top drive, the top drive comprising a quill operable to drive rotation of a drill string and first and second couplings respectively operable to detachably couple the top drive to the first and second chain loops. The chain loops may each comprise transversely-extending longitudinally spaced apart pins and the first and second couplings each comprise a rotatable member projecting from the top drive and engageable between adjacent pins of one of the chain loops, an end of the rotatable member having opposed projecting ears wherein a dimension between outer edges of the ears exceeds a spacing between the adjacent pins. Ends of the pins may be formed to taper in a direction at right angles to the projection of the ears. Surfaces of the rotatable member inward from the ears may be radiused to match a radius of curvature of the pins. In particular, radii of the ears in multiple planes may create a compound curve that matches the pins. A track may extend parallel to the chain loops wherein the top drive is slidably mounted to the track and the track is pivotally coupled to the tower. A hoist may be coupled to the top drive and operative to lift the top drive up the track.
In some embodiments, the drive is connected to drive the chain loops by drive sprockets that engage exterior sides of the chain loops. The drive sprockets may each be located between a pair of idler sprockets, the idler sprockets mounted in an interior of the corresponding chain loop. In alternative embodiments one or more drive sprockets are located inside each of the chain loops. In some embodiments, two drive motors for driving the chain loops are provided and the two drive motors are synchronized. They may be mechanically synchronized such as by a chain or a common rotating shaft connected to each of the two drive motors (e.g. by angle drives). They may also be synchronized electronically.
In some embodiments, the chain loops follow parallel paths and each of the paths has a straight section. A midline between the two straight sections (i.e. the straight section of each chain loop) may be substantially aligned with a wellbore. The straight section may be at least as long as a drill string section. The straight section is at least 50 feet (about 15 m) in length in some embodiments and may be significantly longer than this.
In some embodiments, the chain loops carry four crossheads and the four crossheads are equally spaced apart along the chain loops. The crossheads may be spaced apart along the chain loops by distances that are approximately equal to multiples of the length of tubulars to be handled by the apparatus.
In some embodiments, the elevators are mounted for rotation relative to the crossheads and the center of rotation of the elevator corresponding to a centerline of a drill string section supported by the elevator.
In some embodiments described here, one or more of the elevators may comprise first and second support members each pivotally mounted to a base for rotation about respective horizontal pivot axes, the first and second support members pivotally rotatable about their respective horizontal pivot axes between, a joint-supporting configuration and an open configuration. In the joint-supporting configuration, portions of adjoining edges of the first and second support members each define a corresponding portion of an aperture dimensioned to pass a generally vertical drill pipe extending along a centerline and a top face of each of the first and second members defines a corresponding portion of a joint-supporting surface extending peripherally around the aperture for supporting a drill string section. In the open configuration, the top faces of each of the first and second support members are spaced apart from one another by a distance sufficient to pass a vertical drill pipe extending along the centerline. The base and the first and second support members in the open configuration define an opening dimensioned to allow a vertical drill string section to be passed from an outside edge of the base to the centerline when the support members are in the open configuration.
In some embodiments, the elevator is mounted to the crosshead for rotation about a generally vertical axis centered relative to the aperture. The elevator may comprise a latch operable to hold outside ends of the first and second support members together when the first and second support members are in the joint-supporting configuration. The latch may comprise first and second latch members, a hook on one of the first and second latch members and a loop on the other one of the first and second latch members, the first latch member fixedly mounted to the first support member, the second latch member mounted to rotate about the horizontal pivot axis of the second support member and an actuation mechanism connected to cause the second latch member and the second support member to rotate in opposite directions about the horizontal pivot axis of the second support member.
Optionally, the second latch member may comprise a rod extending coaxially through the second support member along the horizontal pivot axis of the second support member and the actuation mechanism comprises eccentric pins projecting from the rod of the second latch member and the second support member and an actuator arranged to urge the eccentric pins to move in opposing arcs relative to the horizontal pivot axis of the second support member, thereby causing the rod of the second latch member and the second support member to counter-rotate relative to one another. The actuator mechanism optionally comprises a yoke engaging the eccentric pins, a first linear actuator arranged to move the yoke in a first direction and a second linear actuator arranged to move the yoke in a second direction opposed to the first direction. The first and second linear actuators may be mounted to the crosshead, engage abutment surfaces of the yoke without being attached to the yoke. In some embodiments, the first and second linear actuators are replaced by a single double-action linear actuator attached to the yoke.
In some embodiments, the actuation mechanism comprises a yoke engaging first and second cams for rotating the first and second support members and a third cam arranged to rotate the second latch member opposite the direction of rotation of the second support member. In some embodiments, the first and second support members each comprise a collar removably affixed to a rotating piece wherein the collars.
In some embodiments, the drilling apparatus comprises a control system connected to control the actuators to transfer weight of a supported drill string from one of the elevators to a next one of the elevators, the control system comprising a programmable controller, an interface connecting the programmable controller to operate the actuators to selectively raise or lower each of the elevators and load sensors operative to supply signals to the programmable controller, the load signals indicative of loads being carried by each of the elevators. The actuators may comprise hydraulic actuators and the load sensors comprise pressure sensors connected to measure pressure of hydraulic fluid in the hydraulic actuators.
In some embodiments, the drilling apparatus comprises a mud can. The mud can may comprise a hollow cylinder, a handle in fluid connection with a cavity of the hollow cylinder and an outlet for providing suction to the hollow cylinder through the handle. The mud can may be locatable over or may surround a drill string connection while the connection is uncoupled to collect drilling fluids that are thereby released.
In some embodiments, the mud can comprises one or more inflatable seals arranged within the hollow cylinder. In other embodiments, the expandable seals may be employed. Some embodiments comprise a controller for selectively inflating each of the one or more inflatable seals arranged within the hollow cylinder. In some embodiments, the crossheads are tiltable to allow the mud can to pass from a drill string connection above the crosshead to a drill string connection below the crosshead. In some embodiments, the mud can pass from a drill string connection above the crosshead to a drill string connection below the crosshead without tilting the crosshead.
Another aspect of the invention provides mud cans. A mud can may comprise a hollow cylinder, a substantially hollow handle in fluid connection with a cavity of the hollow cylinder and an outlet for connecting to a suction unit to provide suction to the hollow cylinder through the handle. The mud can may be locatable over a drill string connection while the connection is uncoupled to collect drilling fluids that are thereby released. A mud can may optionally comprise additional features. Various additional features are described below. One skilled in the art would understand that the features below can be added to a mud can in any logical combination.
In some embodiments, the mud can comprises one or more inflatable seals arranged within the hollow cylinder to improve suction. The one or more inflatable seals may comprise a first annular seal inflatable to create a seal between an interior surface of the cavity and a circumference of a first drill string section. The one or more inflatable seals may comprise a second annular seal inflatable to create a seal between an interior surface of the cavity and a circumference of a second drill string section. The handle may define an aperture for allowing a rotatable jaw to rotate through the aperture when the mud can is installed on a crosshead. An axial length of the hollow cylinder may be greater than a length of a coupling between adjacent drill string sections.
Another aspect of the invention provides a method for uncoupling adjacent drill string sections. The method comprises passing the drill string through a cavity of a mud can, unthreading a first drill string section from a second drill string section, locating the mud can substantially over the connection, applying suction to the cavity of the mud can to capture drilling fluid released by unmaking the connection, unstabbing the first drill string section from the second drill string section, and capturing drilling fluid released by the unstabbing within the mud can. The method may optionally comprise additional steps. Various additional steps are described below. One skilled in the art would understand that the steps below can be added to the methods for uncoupling adjacent drill string sections in any logical combination or order.
In some embodiments, before applying suction to the cavity, the method comprises inflating a first seal around a circumference of the first drill string section and/or inflating a second seal around a circumference of the second drill string section. After unstabbing, the method may comprise moving the mud can past a second elevator. In some embodiments, this comprises tilting the elevator. In some other embodiments, moving the mud can past the second elevator comprises passing the mud can through an opening in the second elevator, the opening being larger in diameter than the mud can.
Another aspect of the invention provides drilling elevators. The drilling elevator may comprise a first shaft rotatably mounted on a platform for rotation about a longitudinal axis of the first shaft and a second shaft substantially parallel to the first shaft, rotatably mounted on the platform for rotation about a longitudinal axis of the second shaft. The first and second shafts respectively may comprise first and second collar portions. The first and second shaft are rotatable between a closed configuration in which the first and second collars form a drill string supporting surface and an open configuration in which the first and second collars are spaced apart from one another to allow a drill string to pass through a space therebetween. Various optional features of drilling elevators are described herein. One skilled in the art would understand that various combinations of those features may be combined in different embodiments of the drilling elevators.
In some embodiments, the first and second collars abut one another in the closed configuration to form the drill string supporting surface. In some embodiments, the platform is rotatably mounted to a base. A plurality of roller bearings between the platform and the base may allow rotation of the platform relative to the base. In some embodiments, the first and second collars are removably mounted to the first and second shafts.
In some embodiments, the first and second linear actuators are arranged to force a yoke in opposite directions, the yoke attached to each of the first and second shafts by first and second cams respectively to translate linear motion of each of the first and second linear actuators into rotation of the first and second shafts, wherein actuation by the first linear actuator forces the first and second shafts into the closed configuration and actuation of the second linear actuator forces the first and second shafts into the open configuration. Rotation of the first and second shafts may comprise rotation of the first shaft in a first direction and rotation of the second shaft in a second direction, the second direction opposite to the first direction. In some embodiments, the first and second linear actuators abut but are not attached to the yoke.
In some embodiments, moving between the closed configuration and the open configuration comprises rotating the first and second shafts in opposite directions.
In some embodiments, the drilling elevator comprises a latching mechanism to maintain alignment of the first and second shafts in the closed configuration. The latching mechanism may comprise a hook portion attached to one of the first and second shafts and a loop portion attached to the other of the first and second shafts. The first and second linear actuators may be arranged to force a yoke in opposite directions, the yoke attached to each of the first and second shafts by first and second cams respectively to translate linear motion of each of the first and second linear actuators into rotation of the first and second shafts wherein actuation by the first linear actuator forces the first and second shafts into the closed configuration and actuation of the second linear actuator forces the first and second shafts into the open configuration. A third cam may be arranged to translate linear motion of the first and second linear actuators into rotational motion of the hook portion, rotational motion of the hook portion being in an opposite direction of rotational motion of the one of the first and second shafts. Translating linear motion of the first and second linear actuators into rotational motion of the hook portion may comprise the third cam rotating a hook shaft arranged within the one of the first and second shafts, wherein the hook shaft is connected to the hook portion.
Another aspect of the invention provides apparatuses for mounting a drilling tool to a pair of parallel chains where the chains each comprise transversely-extending longitudinally spaced apart rollers. An apparatus may comprise first and second couplings comprising first and second rotatable members projecting from the drilling tool and engageable between adjacent rollers of one of the chains, an end of the rotatable member having opposed projecting ears wherein a dimension between outer edges of the ears exceeds a minimum spacing between the adjacent rollers. The apparatus may optionally comprise additional features. Various additional features are described below. One skilled in the art would understand that the features below can be added to an apparatus in any logical combination.
In some embodiments, ends of the rollers are formed to taper in a direction at right angles to the projection of the ears. The surfaces of the rotatable member inward from the ears may be radiused to match a radius of curvature of the rollers. A dimension of the rotatable members orthogonal to the dimension between outer edges of the ears may be less than the minimum spacing between the adjacent rollers.
In some embodiments, mounting the drilling tool to the pair of parallel chains comprises inserting the first rotatable member into a spacing between adjacent rollers on a first one of the chains and inserting the second rotatable member into a spacing between adjacent rollers on a second one of the chains and rotating the first and second rotatable members approximately 90 degrees to lock the rotatable members between the adjacent rollers.
In some embodiments, actuators are provided for rotating the first and second rotatable members. The actuators may comprise any type of actuator such as linear actuators or rotary actuators. Sensors may be provided to monitor engagement of the rotatable members with the chains. The drilling tool may comprise any type of drilling tool, such as but not limited to top drives and make break units.
Another aspect of the invention provides an apparatus for supplying power to one or more tools suspended from a pair of rotating parallel chain loops. The apparatus may comprise a rotary union located within the chain loops and one or more power cables, extending from the rotary union, for supplying power to the tools suspended from the pair of parallel chain loops. Each of the one or more power cables passes through a hollow roller link in one or more of the chain loops to avoid tangling as the parallel chain loops rotate and then is connected to the one or more tools. The apparatus may optionally comprise additional features. Various additional features are described below. One skilled in the art would understand that the features below can be added to the apparatuses in any logical combination.
In some embodiments, each of the one or more power cables comprises a rotary union as it passes into the hollow roller link. In some embodiments, separate power cables for each tool. In other embodiments, a single power cable that extends along the length of the pair of rotating parallel chains loops and supplies power to each of the one or more tools. A plurality of additional power cables may extend from the single power cable that extends along the length of the pair of rotating parallel chain loops to power each of the one or more tools. The one or more power cables may be retractable.
The power cables may comprise hydraulic power cables or electrical power cables or combinations of both. The power cables may comprise pressure hoses and return hoses. The pressure hose may extend along a first chain of the pair of parallel chain loops and the return hose may extend along a second chain of the pair of parallel chain loops.
The rotary union may comprise a fixed port for receiving power and one or more rotary ports for supplying power to the one or more power cables that extend therefrom.
Further aspects and example embodiments are illustrated in the accompanying drawings and/or described in the following description.
The accompanying drawings illustrate non-limiting example embodiments of the invention.
Throughout the following description, specific details are set forth in order to provide a more thorough understanding of the invention. However, the invention may be practiced without these particulars. In other instances, well known elements have not been shown or described in detail to avoid unnecessarily obscuring the invention. Accordingly, the specification and drawings are to be regarded in an illustrative, rather than a restrictive sense.
One aspect of this invention provides apparatus useful for tripping a drill string. Such apparatus is operable to raise the drill string, uncouple an uphole segment from the drill string, and hand off that uphole segment to a storage apparatus where it can be stored until needed again. In some embodiments, the process is performed continuously such that removal of the uphole drill string section occurs while the drill string is being lifted out of the borehole.
Apparatus 10 comprises a plurality of connection units 14 which are arranged to travel along a closed path 15. Path 15 includes a section 15A aligned with well center 12A. Section 15A is typically vertical. In some embodiments section 15A and well center 12A are inclined at some angle to vertical.
Connection units 14 each include an elevator 14A. An elevator is a mechanism for grasping and holding drill string 13. Typical drill string sections have tapered or square upset tooljoints near their ends. In some embodiments, elevator 14A is designed to close around the drill string section to engage such tooljoints. In some embodiments elevator 14A may comprise a slip type elevator that can grip a drill string 13 at any point. When the elevator is closed around the drill string section, the elevator can support the weight of the drill string section (and any other parts of the drill string coupled below the drill string section being supported by the elevator). Elevators are commercially available. Some elevators are designed to carry weights of 150 tons, 250 tons, 350 tons, or more.
Connection unit 14 also includes an elevation adjuster 14B which is operable to shift elevator 14A up or down relative to the rest of connection unit 14. Elevation adjuster 14B may be controlled to transfer weight of a drill string between different elevators 14A and also to compensate for variations in the lengths of tubulars. In some embodiments elevation adjuster 14 allows the entire connection unit 14 to be scoped up or down relative to path 15.
Connection unit 14 may also include a tilt adjuster 14F which is operable to tilt links supporting elevator 14A at an angle relative to path 15. Tilt adjuster 14F may be used to shift elevator 14A laterally relative to path 15. For example, when a top drive is coupled to drill string 13 as described elsewhere herein, tilt adjuster 14F may be controlled to displace coupling unit 14 so that a drill string section supported by the elevator 14A of the coupling unit 14 does not interfere with the top drive. This may allow the supported drill string section to be brought quickly into place for coupling to the top end of drill string 13 after the top drive has been disconnected from drill string 13. A tilt adjuster 14F may be used to tilt an elevator 14A so that it does not interfere with a pipe handling system 17 arranged to deliver drill string sections to and from apparatus 10.
Tilt adjuster 14F may comprise, for example, a tilt gear 58K driven by a motor 58L as illustrated in
Tilt of connection units 14 may be driven actively (e.g. by a tilt adjuster 14F) or passively (e.g. a connection unit 14 may encounter ramps, tracks, rollers or the like that cause the path taken by the elevator 14A of the connection unit to deviate from path 15 at different locations around path 15 as the connection unit 14 circulates).
Connection units 14 may also each comprise an engagement/disengagement unit (which may also be called a make/break unit) which is operable to make or break a connection between adjacent drill string sections. In some embodiments, the engagement/disengagement unit 14C comprises jaws which are engageable with couplings of adjacent drill string sections 11 and are rotatable relative to one another to screw the threaded coupling between the two sections 11 together or to unscrew the threaded coupling between the two sections 11 so that the sections are separated from one another.
In the illustrated embodiment, connection unit 14 includes a fixed jaw 14D which is disposed below a rotatable jaw 14E. Fixed jaw 14D may hold a drill string section that is being supported by elevator 14A so that the supported drill string section does not rotate. Rotatable jaw 14E may then engage and rotate a drill string section that is above the supported drill string section to either couple or uncouple the drill string sections.
Engagement/disengagement unit 14C has a configuration which allows a drill string or drill string section to pass into the engagement/disengagement unit from one side. For example, fixed jaw 14D and rotatable jaw 14E may each comprise a gap wide enough to receive a drill string section. When the gaps are aligned with one another engagement/disengagement unit 14C may be moved transversely relative to a drill string section from a position adjacent to the drill string section until the drill string section has entered the gap.
A centralizer may be provided to move an end of a drill string section onto well center (for example to facilitate stabbing the drill string section into the uphole end of drill string 13). The centralizer may be of any suitable type. A centralizer may be included as part of a connection unit 14, as part of a separate make/break machine, as a separate device mounted on a crosshead or the like. It is generally desirable to bring the end of a drill string section onto well center with a small tolerance (e.g. ¼ inch). In some embodiments a centralizer may include a pair of moving arms that bring the drill string section to a fixed center position.
Some drilling operations are conducted in locations that are very windy. High wind loads may blow a section of drill string around and make the drill string section harder to handle. In some embodiments elevator actuators 14B and/or tilt adjuster 14F are actuated as tubulars are being carried in a manner that provides live damping of wind-induced oscillations. In an example embodiment, sensors associated with connection units 14 sense the onset of wind-induced motion of a supported drill string section and a control system operates actuators (e.g. elevator adjusters 14B and/or tilt adjuster 14F) to dampen the motion in response to the sensor signals.
Tubulars that are being carried by elevators 14A associated with connection units 14 may optionally be gripped with the rotatable and/or backup jaws of an engagement/disengagement unit 14C as they are being carried to stabilize the tubulars against, among other things, wind-induced motions or vessel dynamics.
Connection units 14 are spaced apart along path 15 by a distance D such that the elevator 14A of a first one of the connection units 14-1 can engage and support a drill string section 11-1 that is being added to or taken off of the uphole end of the drill string. A second connection unit 14-2 can have its elevator 14A engaged with the next drill string section 11-2 that drill string section 11-1 is being coupled to or uncoupled from. In other words, on vertical section 15A, two connection units 14 are spaced apart from one another by a distance D that is approximately equal to the lengths of the drill string sections 11 which make up drill string 13. In some embodiments drill sections 11 are about 30 feet (about 10 m) or about 45 feet (about 15 m) long. Variations in the lengths of individual drill string sections 11 may be accommodated by adjusting elevator adjusters 14B.
A pipe handling system 17 provides drill string sections to apparatus 10 or takes away drill string sections 11 from apparatus 10 as required.
In an example method of operation, connection units 14 are circulating continuously along path 15. For example, connection units may travel along vertical section 15A at a speed of ½ to 4 feet per second (about 15 cm/sec to 125 cm/sec). 1½ feet/second (about 45 cm/second) is typical. While connection units 14 circulate around path 15 the weight of drill string 13 may be transferred from the elevator 14A of one connection unit 14 to the next to either hoist drill string 13 (e.g, for tripping out) or to lower drill string 13 (e.g. for tripping in). At the same time drill string sections may be removed from (for tripping out) or coupled onto (for tripping in) the uphole end of drill string 13.
For clarity,
As illustrated in
Once connection unit 14-2 has engaged drill string section 11-2, the weight of drill string 13 can be handed off so that drill string 13 is supported by connection unit 14-2. This may be done by one or both of: lowering the elevator 14A of the topmost connection unit 14-1 using elevation adjuster 14B (as in block 200E), and raising the elevator 14A of the lowermost connection unit 14-2 using elevator adjuster 14B (as in block 200F). In either case, a sensor may detect significant decrease in the weight carried by elevator 14A of the higher connection unit 14-1 (as in block 200G) and/or an increase in weight carried by the elevator 14A of the lower connection unit 14-2 (as in block 200H). For example, where elevators 14A are supported by hydraulic cylinders the sensor(s) may monitor lift cylinder pressure at connection units 14-1 and/or 14-2 to determine when the transfer of weight of drill string 13 to connection unit 14-2 is complete (as indicated at block 200I). Since the weight of the drill string is now being supported by the lowermost connection unit 14-2, the topmost drill string section 11-1 may be uncoupled from the rest of drill string 13 (block 200J), as illustrated in
For example, fixed jaw 14D may grip the upper end of drill string section 11-2 and thereby prevent rotation of the upper end of drill string section 11-2 and the rest of drill string 13 while rotatable jaw 14E grips and turns the uppermost drill string section 11-1 thereby uncoupling section 11-1 from the rest of drill string 13. Simultaneously with this, elevator adjusters 14B on one or both of the first and second connection units 14 may be operated to lift the uppermost drill string section clear of drill string section 11-2 to which it was coupled (i.e. ‘unstab’ the uppermost drill string section). The uncoupling of section 11-1 may occur as connection units 14 continue to circulate around path 15.
Block 201D determines if there is enough vertical distance to finish uncoupling drill string sections 11 at the current speed of hoisting before uppermost connection unit 14-1 leaves the straight front side 15A of path 15. If so (YES result from block 201D), then the uncoupling may continue to completion and un-stabbing may occur (blocks 201F and 201G). If there is not enough vertical distance to finish uncoupling sections 11-1 from section 11-2 at the current speed of hoisting (NO result from block 201D), then the hoist speed is reduced at block 201E.
By not requiring uncoupling to happen at any specific location along path 15, this breakout sequence does not require the sequence of events to occur within exacting tolerances and allows for some flexibility.
While the above events are occurring, connection units 14-1 and 14-2 may be continuously moving upwards along vertical section 15A of path 15. When the uppermost connection unit 14-1 reaches the top of vertical section 15A, the now-uncoupled uppermost drill string section 11-1 that it is still carrying is taken over the top end 15B of path 15 and carried laterally out of alignment with the rest of drill string 13. Drill string section 11-1 may then be carried downward along the backside 15C of path 15. Somewhere on the backside 15C of path 15, the drill string section 11-1 being carried by the first connection unit 14-1 may be disconnected from the elevator 14A and handed off to a pipe handling system 17 which takes and stores the drill string section.
In some embodiments the elevators 14A of connection units 14 are movable laterally relative to path 15 when the connection units are travelling down the back side 15C of path 15. This allows elevators 14A to be shifted laterally e.g. by tilting after drill-string sections 11 are passed off to pipe handling system 17. This may allow connection units 14 to pass by the pipe handling system 17 after the drill string section has been handed off. The pass off to pipe handling system 17 may occur in line with path 15 or spaced apart behind path 15 by a distance within the lateral range of motion of connection units 14.
Horizontal displacement of elevator 14A relative to path 15 may be achieved, for example, by pivoting connection unit 14 or a link that supports elevator 14A. Control over the lateral position of elevators 14A may be provided, for example, by an actuator (e.g. a link tilt mechanism such as tilt adjuster 14F) or a track and roller system.
In the meantime, the second connection unit 14-2 has continued to lift drill string 13 up to the point where a third connection unit 14-3 can engage a next drill string section which has been pulled high enough to be engaged by the elevator of the third connection unit 14-3. The process can then be continued with drill string sections being lifted and uncoupled from one another as they travel up vertical section 15A of path 15, carried between two connection units 14. After each drill string section is uncoupled from the rest of the drill string, it is passed off to pipe handling system 17 on the backside 15C of path 15 or at another suitable location.
The process may be reversed in order to add drill string sections 11 to the top of a drill string 13 as the drill string 13 is tripped back down into a borehole.
In some embodiments, a top drive may be removably coupled to move along path 15. This facilitates using apparatus as described herein for drilling as well as for tripping.
In
In
In
Top drive 30 may be coupled to a connection unit 14 (see
As drilling continues, a new drill string section 11 may be handed off to another connection unit 14 which is travelling up on the backside 15C of path 15. As drilling progresses, the new drill string section may be tilted so that it does not damage top drive 30. When drilling has progressed to the point that the connection unit 14 with which the top drive is associated has again reached or is near the bottom of vertical section 15A as shown in
Each of connection units 14 requires power to drive various actuators to perform functions such as raising or lowering the elevator, gripping or ungripping the drill string with a backup jaw, centralizing a drill string section to be added to the drill string, gripping and rotating the drill string, etc. Power may be supplied to connection units 14 in any of various ways.
In one example embodiment illustrated in
In some embodiments hydraulic power is delivered to connection units 14 and electrical power is generated at connection units 14 by hydraulically-driven electrical generators. In some embodiments batteries are carried with connection units 14. The batteries may power sensors, control circuits and/or data communication systems for example. In some embodiments both hydraulic and electrical power are delivered to connection units 14 from a rotary union 40.
Flexible cables or hoses 42 carry the electrical or hydraulic power from rotating ports of rotary union 40 to the individual connection units 14. Each of these flexible cables or hoses may include a rotary coupling or union. Where connection units 14 are supported between circulating elements the flexible cables or hoses 42 may be routed to couplings on an outside face of one of the circulating elements which connect trough the circulating element to the corresponding connection unit 14. For example, the hose may connect to a corresponding connection unit 14 through a rotary union.
Each cable or hose 42 is long enough to reach the corresponding connection unit 14 anywhere along path 15. As connection units 14 circulate around path 15 in either direction, rotary union(s) 40 also rotate. Rotary union(s) 40 may optionally be driven to rotate together with the circulation of the connection units 14 around path 15.
As illustrated in
In an example embodiment, each of connection units 14 is connected to receive a pressure-side hydraulic hose and a return-side hydraulic hose. In some such embodiments, the pressure side hose may be routed from a hydraulic power unit to a non-rotating port of a first rotary union, from a rotating port of the first rotary union to a first point on path 15 and then connected to pressure-side fittings on all of connection units 14 through one or more hose sections that extend generally along path 15 and circulate around path 15. Similarly, return-side hoses may extend along path 15 from return fittings on each of connection units 14 to a second point on path 15. A return hose may connect the second point to a rotating port of a second rotary coupling. The return path may be completed by a hose extending from a non-rotating port of the second rotary coupling back to the hydraulic power unit. In some embodiments the pressure-side hose extends along a first chain on one side of the apparatus and the return-side hose extends along a second chain on a second side of the apparatus. In some embodiments the chains comprise pins and hydraulic fluid is routed to and/or from connection units 14 through channels that extend through pins of the chains
In some embodiments, separate rotary unions are provided for the pressure and return sides of a hydraulic power supply or for the two or more wires required to complete an electrical circuit. In some embodiments, one rotary union is provided on each side of an apparatus.
Control of the functions of each connecting unit 14 as well as apparatus 10 may be coordinated by a control system which may be made up of one or more controllers. The controllers may, for example, comprise programmable controllers such as PLCs. The controllers may communicate with each of connection units 14 by way of wired or wireless data connections and may also receive status information from the connection units 14 by way of the wired or wireless data connections. Wired data connections may be provided alongside or be integrated with power connections (as described above for example). The control system may control functions such as opening and closing elevators 14A or controlling the gripping and ungripping of drill string sections by jaws 14D and/or 14E, and or controlling rotation of rotatable jaw 14E and/or controlling operation of elevation adjuster 14B. The data communication network may also transmit signals back to the control system.
These signals may include signals such as a reading from a load cell or a hydraulic pressure in the hydraulic circuit controlling elevation adjuster 14B. This signal is indicative of the extent to which a particular elevator is supporting the weight of the drill string. By monitoring this signal, the control system can determine when weight of the drill string has been handed off from one of connection unit 14 to another connection unit 14. Other signals may indicate circumstances such as the presence of a drill string section at a particular location, whether an elevator is closed or open, torque applied to make or break a connection between drill string segments, the current elevation of an elevator 14A (measured, for example, by a linear position sensor), the current status of a pipe handling system and the like.
In some embodiments the control system uses advance knowledge of the lengths of individual drill string sections to be added to or removed from a drill string to position elevators 14A at optimum elevations. By doing so, the apparatus may be made to operate somewhat more quickly since elevators 14A can be pre-positioned at elevations such that the travel of the elevators during hand off from one elevator 14A to the next elevator 14A is reduced.
Knowledge of the lengths of tubulars may be acquired in any of a variety of ways. In some embodiments, pipe handling system 17 includes a system for measuring tubulars. Pipe handling system 17 may pass measurements for the tubulars to the control system. In some embodiments, the control system is configured to store the lengths of tubulars when the tubulars are first handled (e.g. during drilling). For example, the length of a tubular may be measured when the tubular is being coupled into the drill string or being coupled to a top drive. In some embodiments the control system bases a measurement of the length of the tubular on the distance between a top drive coupled to the tubular and an elevator 14A holding the drill string. Once the tubulars have been measured then the length of each tubular is known (as long as the sequence of the tubulars is preserved).
In some embodiments the control system has access to a data store containing the length of each tubular cross-referenced to a machine-readable identifier for the tubular. A reader reads the machine-readable identifier and the control system can then look up the corresponding length in the database. Some example systems for identifying and tracking drill string sections are described in U.S. Pat. No. 4,701,869A; WO2012128735A1; US20100171593A1; US20050230109A1; U.S. Pat. No. 8,463,664B2; and GB2472929A all of which are hereby incorporated herein by reference.
In other embodiments, the length of a drill string section 11 can be detected in real time. Example ways to measure a drill string section include:
Where the length of each drill string section 11 is known in advance, the control system may actuate an elevator adjuster 14B in advance to position the corresponding elevator 14A at an appropriate elevation such that coupling/uncoupling of the tubular from the drill string and/or passing off of the weight of the drill string from one elevator 14A to another can be made with minimum travel of elevator adjusters 14B. This may allow for increased and consistent tripping speeds.
A system as described above may be implemented in various ways.
In the embodiments shown in
Spigots 55 or other attachment members are provided on carriages 58E that are slidable along linear rails 58B. In the illustrated embodiment, each carriage 58E comprises a pair of guide tubes 58F. Suitable bushings or linear bearings 58J within guide tubes 58F facilitate sliding of carriages 58F along linear rails 58B without binding. Guide tubes 58F facilitate spacing bushings or bearings 58J widely apart so that normal forces on bearings or bushings 58J are reduced, thereby reducing friction. Such normal forces resist bending moments on linear rails 58B that may arise as the weight of drill string 13 is applied to base 58C.
Carriages 58E are positioned relative to base 58C by linear actuators 58G. In the illustrated embodiment, actuators 58G comprise hydraulic cylinders. The body 58G-1 of each cylinder is coupled to the corresponding carriage 58E and the rod 58G-2 of each cylinder extends to engage the corresponding bridge 58D. Base 58C (and any apparatus carried on base 58C) can be raised relative to spigots 55 by extending actuators 58G. Base 58C can be lowered relative to spigots 55 by retracting actuators 58G.
In some embodiments, ends of rods 58G-2 are coupled to bridges 58D in a manner that permits certain movements of the rod ends relative to bridges 58D. For example, the coupling may permit rod ends to move laterally and/or to pivot relative to bridges 58D. Such connections may avoid placing side loads on rods 58G-2 even in cases where there is some deflection of frame 58A due to very high loads applied through base 58C.
Apparatus of a wide variety of types may be supported by or from base 58C. In the illustrated embodiment a make/break unit 58H is provided. Other example embodiments may provide only an elevator on base 58C. Make/break unit 58H may comprise one or more motors 58H-1 and 58H-2, as illustrated in
Drive sprockets 63 may be driven, for example, by a hydraulic or electric motor through a suitable power transmission such as a planetary transmission.
In the illustrated embodiment a separate motor 64 is coupled to drive each chain 61. Operation of motors 64 is synchronized such that chains 61 circulate in synch with one another. In some embodiments motors 64 are synchronized by the operation of electronic motor control systems. In some embodiments motors 64 are mechanically synchronized. This may be achieved by providing a mechanical transmission that couples together rotors of motors 64. For example,
Chains 61L and 61R may be sidebar-style chains such as roller chains, for example. Coupling units 14 are pivotally mounted between chains 61L and 61R. In the example embodiment, each coupling unit 14 is connected so that force is transferred to chains 61L and 61R through the centerlines of the chains. Beneficially coupling units 14 may include a rigid cross-member that is coupled to each of chains 61R and 61L and acts as a load equalizer. Elevator 14A may be supported by such a rigid member such that the load carried by elevator 14A is split between chains 16. Such load sharing is facilitated by connecting coupling units 14 to chains 61 using couplings which can accommodate some changes in alignment of the rigid cross member. For example, the rigid cross member may couple to chains 61 using spherical bearings, an example of which is described below.
Advantageously in some embodiments, drive sprockets 63 engage chains 61 on the outside of the loops of chains 61. This facilitates disassembly of mast 60. For example, sprockets 63 may be provided on a first component and the part of mast 60 that carries chains 61 may be on a second component. The first and second components may be separated for transport and assembled to provide apparatus 10 at a well site. Each drive sprocket 63 may engage a corresponding one of chains 61 in a gap between a pair of other sprockets such that appropriate wrap is provided around the drive sprocket 63. This construction permits assembly of apparatus 10 without taking chains 61 apart.
In some embodiments a top drive 30 or other apparatus is removably coupled to a roller chain (e.g. chains 61) or other sidebar type chain by a coupling 70 of the type illustrated in
As shown in
In the illustrated embodiment, two trunnions 72 are supported by a frame 73. The centers of trunnions 72 are spaced apart by a distance equal to a distance between the center lines of chains 61. Bearing surfaces 72E are rotatably supported by frame 73 (e.g. in suitable bushings or bearings). Expanded portions 72F keep trunnions 72 from pulling out from frame 73.
Suitable actuators are provided to rotate trunnions 72 between their unlocked and locked orientations. In alternative embodiments a single actuator may be provided to rotate both trunnions 72 by way of suitable gearing or linkages. Rotary or linear actuator s may be provided to rotate trunnions 72.
Sensors may be provided to verify successful coupling of trunnions 72 to chain 61. In the illustrated embodiment, inclination sensors 75 are provided on each trunnion 72. Inclination sensors 74 can detect the angle of rotation of each trunnion 72. Proximity sensors 76 are also provided. When coupling 70 is successfully coupled to chains 61 each of proximity sensors 76 is located close to a roller 61A of the corresponding chain 61. A safety mechanism (e.g. an electronic controller) may detect successful coupling of coupling 70 to chains 61 by verifying that both of proximity sensors 76 detect a roller (or other suitable part) of a chain 61 and also that inclination sensors 75 indicate that both of trunnions 72 are oriented in their engaged (‘locked’) configurations.
Coupling 70 may be applied to couple any desired equipment to chains 61. For example, a top drive or a make break unit may be coupled anywhere along chains 61 using coupling 70. Coupling 70 may be located such that the quill of a top drive attached between two chains in a vertical section of the chains is in the same plane as the centerlines of the chains.
In other embodiments a top drive or other apparatus may be coupled indirectly to circulating elements such as chains 61. This may be done, for example, by providing a coupling on the top drive that engages with a corresponding coupling provided on a cross head.
It is beneficial for elevators 14A to be suspended so that their weight (and much more-significantly the weight of the suspended drill string 13) is applied in alignment with the centers of rollers 61A of chains 61. As mentioned above, it is also beneficial to provide a system that facilitates load sharing between chains 61 such that each chain 61 supports a similar proportion of the load.
Arrangement 80 includes hollow connection rollers 82 which are provided at each location where it is desired to a couple a connection unit to a chain 61. Rollers 82 may be mounted to rotate relative to the plates between which they are supported. Spigots 55 which support apparatus (e.g. an elevator or connection unit or other apparatus to be supported) project into bores 82A of connection rollers 82. Connection rollers 82 are coupled to adjoining pins 61D of chain 61 by outer chain plates 61G and 61H on one side and by inner chain plates 61I and 61J on an opposing side. Chain plates 61G and 61H are axially retained relative to pin 61D by retaining bolt assembly 61F.
A bearing 83 is located at or near the center of bore 82A (e.g. half-way between inner chain plates 61I and 61J). Bearing 83 allows rotation of spigot 55 relative to connection roller 82. Bearing 83 is held in place on the end of spigot 55 by a retaining plate 84. In the illustrated embodiment, bearing 83 is a spherical bearing. Spherical bearing 83 accommodates imperfect alignment between the axis of spigot 55 and the axis of connection roller 82. This in turn facilitates load sharing between spaced-apart chains 61. A spacer 85 holds bearing 83 in place.
Mirror image arrangements 80 may be provided on a pair of spaced apart chains 61. Arrangements 80 facilitate transfer of force to chains 61 at locations that are centered both side-to side and front-to-back on chains 61 (i.e. on the center lines of chains 61).
A pair of shafts 308A and 308B (collectively referred to as shafts 308) are mounted substantially parallel to one another on platform 302. It is not mandatory that shafts 308 are parallel. In some embodiments shafts 308 are angled slightly relative to one another.
Shafts 308A and 308B each comprise a semi-circular collar 310. Shafts 308 are rotatable about their respective longitudinal axes to cause semi-circular collars 310 to move between a closed position in which collars 310 abut one another to create a substantially complete circular collar 312 for supporting an upset of a drill sting section 11 (as depicted in
An example arrangement for controlling rotation of shafts 308A and 308B about their respective longitudinal axes applies actuators 312A and 312B, as best seen in
In the particular arrangement shown, actuator 312A pushes link 314 away from actuator 312A. Movement of link 314 causes rollers 316A and 316B to cause shaft 308A to rotate clockwise and shaft 308B to rotate counterclockwise thereby spacing apart collars 310 and opening elevator 300. To close elevator 300, actuator 312B pushes link 314 away from actuator 312B to reverse the direction of rotation of shafts 308 and create the substantially complete circular collar 312, as shown in
Elevator 200 has an open side through which a tubular may be brought into a position where it can be engaged by collars 310 and a closed side. In some embodiments shafts 308 are angled so that they are farther apart at the open side of elevator 200.
It is not necessary to fix actuators 312A and 312B to link 314. Actuators 312A and 312B may be fixed to a crosshead or other fixed structure, thereby allowing platform 302 to be rotated relative to actuators 312A and 312B. When link 314 is aligned with actuators 312A and 312B, the actuators may be operated to engage abutment surfaces on link 314 and thereby push link 314 so as to rotate shafts 308 between the open and closed positions as desired. Rotation of platform 302 may be employed in conjunction with make/break unit 14C for coupling/uncoupling drill string sections 11. Rotation of platform 302 could allow rotation of drill string 13 while elevator 300 is supporting drill string 13. Such rotation can be driven by a top drive or by a make break unit (e.g. rotatable jaws 14E) or by external means.
To ease operation, a latch sensor 322A may be provided to allow an operator or control system to monitor the degree of rotation of elevator 14A. Latch sensor 322A may comprise a proximity sensor that senses when shaft 314A of link 314 protrudes up (signifying that elevator 300 is in the open position) or does not protrude (signifying that elevator 300 is in the open position). A rotational sensor 322B may be provided to monitor whether or not platform 302 is aligned with base 304 to allow drill string sections 11 to travel through opening 324.
In some embodiments, elevator 300 may comprise a latch mechanism 318 for preventing shafts 308 from spreading apart while carrying the weight of drill string 13. Spreading forces can be particularly large in the case where elevator 300 is supporting drillpipe with tapered tool joint upsets (typically 18 degrees). The illustrated example latch mechanism 318 comprises a loop member 318A and hook member 318B. In the illustrated embodiment, loop member 318A is fixed to shaft 308B and rotates as shaft 308B rotates while hook member 318B is connected to a secondary shaft 320 within shaft 308A that rotates in an opposite direction to the rotation of shaft 308A due to cam 316C. In this way, as shafts 308 are rotated into a closed position, loop member 318A is rotated toward shaft 308A and hook member 318B is rotated into an opening 318A-1 of loop member 318A to prevent movement of shaft 308A relative to shaft 308B when in the locked configuration. Although only one embodiment of latch mechanism 318 is depicted, one skilled in the art that various embodiments for maintaining alignment of shafts 308 could be employed instead. For example, the hook and loop members could be swapped.
Collars 310 may be configured to accommodate various sizes and shapes of drill string sections 11. In some embodiments, collars 310 are detachable from shafts 308. For example, as best seen in
In some embodiments, elevator 300 is partly or completely encapsulated within a cross head bridge frame such as is depicted in
In some embodiments an elevator 300 or a conventional elevator is mounted for rotation such that its opening side can be turned to face in different directions. For example, such embodiments may provide an elevator that forms a structural element of a crossbeam and can be rotated so as to accept a drill string section 11 from either side of the crossbeam. One way to provide a structure in which a rotating element can form a structural component of a crossbeam is described in U.S. Pat. No. 7,794,192 which is hereby incorporated herein by reference for all purposes. In some embodiments the elevator is rotatable by at least approximately 180 degrees. In some embodiments the elevator is automatically rotated as it passes over the top end of path 15 such that the opening of the elevator faces away from path 15 both when the elevator is on front side 15A of path 15 and when the elevator is on back side 15C of path 15.
In some embodiments where power generators are carried around path 15 by chains (e.g. chains 61 in embodiments described herein) A power generator is located on one side of the chain, the flexible member is located on an opposing side of the chain, and power is provided to the power generator by way of a shaft that extends through a hollow pin of the chain.
Drive loops 91 alternate between inner drive loops 91A and outer drive loops 91B. Inner drive loops 91A drive or are driven by inner sprockets 92A and outer drive loops 91B drive or are driven by outer sprockets 92B. Sprockets 92A and 92B are unitary or coupled together such that a drive loop 91A drives the next drive loop 91B which drives the next drive loop 91A, and so on around chain 61.
A power generator may be located at any pin 61D of chain 61 and driven by the sprockets 92 at that pin 61D. In some embodiments (including the illustrated embodiment—see
Power may be transferred from a stationary power unit (e.g. an engine or motor) to the interconnected drive loops 91 by way of sprockets 92C that are coupled to rotate with sprockets 92A and 92B.
Most drive belts or drive chains require a tensioner to maintain a desired working tension. In some embodiments a separate tensioner is provided for each one of drive loops 91. The tensioners may, for example, comprise rollers or idler sprockets biased against the drive loops by springs or the like. In an alternative embodiment illustrated in
Power delivery system 100 includes a drive system comprising motors 94, drive loop 95, idlers 96 and drive sprockets 97.
Some or all of sprockets 102C and 102D are extended so that they can be driven by a drive loop 95 in the same manner described above with respect to power delivery system 100. In the illustrated embodiment, sprockets 102E are extended to engage a drive loop 95. One or more power generators may be driven by any of sprockets 102D or 102E.
In some alternative embodiments one or more prime movers and a source of fuel for the prime mover are mounted to be carried around path 15. For example, a fuel cell may be carried around path 15. Electricity generated by the fuel cell may be used directly to drive electrical actuators and or used to drive an electric motor connected to drive a hydraulic pump. Fuel may be provided to the prime mover periodically (e.g. a tank carried to move along path 15 may be filled during periods when the apparatus is not circulating around path 15 or provisions may be made to supply fuel to the prime mover while the apparatus is circulating around path 15. As another example of a prime mover an engine connected to drive a hydraulic pump and or an electrical generator may be supported to circulate around path 15. Power may be routed from the prime mover to destinations where the power is needed along path 15 (unless the prime mover is already located at the location at which power is required) by way of flexible hoses or cables extending along path 15.
In some embodiments a make/break unit is provided on a track 112. In such embodiments the make break unit may be positioned as required along front side 15A of path 15 to make or break connections between drill string sections. In some such embodiments make/break units that travel around path 15 (e.g. carried by chains 61) are not provided. In other embodiments a rotatable jaw is provided on a track 112. The rotatable jaw may cooperate with backup jaws that are mounted to travel around path 15 to make or break connections between drill string sections. In other embodiments a non-rotatable backup jaw is carried on a track 112. The backup jaw on track 112 may be positioned and operated to cooperate with a rotatable jaw that is supported to travel around path 15.
Tracks 112A and 112B are pivotally mounted so that they can be swung in toward well center or swung away from well center. In the embodiment shown in
In the illustrated embodiment, a top drive 116 is provided on track 112A and a make/break unit 117 is provided on track 112B. As needed, top drive 116 may be brought to well center by pivoting frame 114 into the configuration shown in
Tracks 112A and 112B may include hoists operable to raise or lower equipment to desired positions along the tracks. Equipment such as a top drive or a mud can may be positioned vertically on a track 112 and then brought into well center when needed. After the equipment has been used it may be re-positioned by hoisting it along track 112. In some embodiments, when drilling, a top drive is positioned along track 112 while track 112 is pivoted away from well center. The top drive is then brought into well center by pivoting frame 114. At this point the top drive may be coupled to chains 61, for example with a coupling 70 as described elsewhere herein. The top drive may then be coupled to the drill string and operated to drill the borehole deeper. During this phase, track 112 may absorb some or all of the reaction torque from the top drive. When it is time to add another drill string section the top drive may be uncoupled from the drill string and uncoupled from chains 61. Track 112 may then be pivoted away from well center and the top drive may be hoisted up track 112 to a starting position for the next drill string section. The process can then be repeated for another drill string section.
A wide range of equipment may be provided on tracks 112. In some embodiments, top drives are provided on both tracks 112A and 112B such that one top drive may be hoisted to a ready-to drill position while another top drive is actively drilling. Such an embodiment provides redundancy in case one top drive requires servicing and may also provide some increase in speed. Frames 114 may be separable from mast 60 for transport.
Apparatus of the type described herein may be configured to make or break couplings between drill string sections in a wide variety of ways. Some of these are illustrated in the accompanying drawings. For example:
Optionally, for the purpose of holding a drill string to receive special purpose or special length drill string sections, conventional slips or other apparatus for holding the drill string may be provided on the drill rig floor. In some embodiments, when it is desired to add an odd-length drill string section (typically a section shorter than other sections) or a drill string section that requires special handling, then drill string 13 may be supported by slips 121 in the drill rig floor. A drill string section 11 may then be presented at or near well center and engaged by an elevator 14A of a coupling unit 14 or an elevator of a top drive. The elevator 14A may then be lifted to bring the drill string section 11 to a vertical orientation from where it can be stabbed into the upper end of the drill string. A portion of mast 60 just above the drill rig floor may be free of cross members which would block the erection of drill string sections 11 of a desired length.
If connection unit 14 is at zero lift, and the handoff window is sufficiently large, the speed of connection unit 14 and the conveyor is maintained until it is detected that the drill string section has landed on the conveyor backstop. This may be detected by a suitably-located sensor and/or by detecting a change in the load on the motor driving the conveyor. A significant change in the torque required to drive the conveyor can be used to indicate that the conveyor is supporting the weight of drill string section 11. If the handoff window is not sufficiently large, then the speed of connection unit 14 may be decreased. If the connection unit 14 is not at zero lift, connection unit 14 may be scoped down until a significant increase in the torque required to drive the conveyor occurs.
A sensor may optionally be provided on connection unit 14 to detect whether drill string section 11 protrudes from elevator 14A, signifying a transfer of weight to the conveyor. At this point, elevator 14A can be opened to complete the transfer of drill string section 11 to the conveyor. After the drill string section has been transferred from elevator 14A to the conveyor of pipe handling system 17 the speed of the conveyor can be increased (e.g. to 150% speed) until the conveyor is in position for the next handoff, at which point this method begins again. One exemplary benefit of this method is that the handoff can occur at any point in the handoff window and is not required to happen at a precise moment which would require tighter tolerances.
Other optional equipment that may be provided on a rig floor to handle exceptional circumstances, special drill string sections and the like include: an independent make/break machine, slips and a power tong.
During tripping out, it is common for drill string sections 11 to still contain drilling mud/fluid. Consequently, as drill string sections 11 are uncoupled, drilling mud may be released in an unwanted manner onto the drilling rig. In some embodiments, a mud can is provided to capture any drilling mud that is released upon uncoupling of drill string sections 11. The mud can surrounds a joint comprised of two adjacent drill string sections 11 as the adjacent drill string sections 11 are uncoupled and may optionally provide suction to assist in removal of any unwanted drilling mud from the joint as it is uncoupled. In some embodiments a mud can comprises a tubular body that is engaged over the top of a tubular string and is advanced sown the string without being removed from the string as tripping out progresses. Such a mud can does not need to be split. In some embodiments the mud can is passed through an open elevator (e.g. an open elevator 300 as described above).
Once mud can 400 is over top of the joint, optional lower seal 420 and upper seal 422 may be expanded (e.g. inflated or mechanically expanded) (as depicted in
As best depicted in
Returning to
Once drill string section 11-1 and 11-2 have been uncoupled and mud can 400 has finished its job, mud can 400 may be translated down drill string 13 to the next joint (i.e. between drill string section 11-2 and 11-3). In some embodiments, seals 420 and 422 are first deflated (as depicted in
Mud can 500 may be operated in a similar manner as mud can 400. However, mud can 500 does not require tilting of connection unit 14 since the throat of elevator 300, in its open position as discussed herein, is sufficiently wide for mud can 500 to pass through, as best seen in
In some embodiments, mud can 500 does not include seals 420, 422. Instead, mud can 500 may seal against collars 310 of elevator 300 to prevent drilling fluid from escaping. In particular, collars 310 may comprise seals 310B and 310C as depicted in
Some embodiments provide significant safety advantages as compared to other drilling systems. These safety advantages may include:
Some advantages of certain embodiments include one or more of:
Unless the context clearly requires otherwise, throughout the description and the claims:
Words that indicate directions such as “vertical”, “transverse”, “horizontal”, “upward”, “downward”, “forward”, “backward”, “inward”, “outward”, “vertical”, “transverse”, “left”, “right”, “front”, “back”, “top”, “bottom”, “below”, “above”, “under”, and the like, used in this description and any accompanying claims (where present), depend on the specific orientation of the apparatus described and illustrated. The subject matter described herein may assume various alternative orientations. Accordingly, these directional terms are not strictly defined and should not be interpreted narrowly.
While processes or blocks are presented in a given order, alternative examples may perform routines having steps, or employ systems having blocks, in a different order, and some processes or blocks may be deleted, moved, added, subdivided, combined, and/or modified to provide alternative or subcombinations. Each of these processes or blocks may be implemented in a variety of different ways. Also, while processes or blocks are at times shown as being performed in series, these processes or blocks may instead be performed in parallel, or may be performed at different times.
In addition, while elements are at times shown as being performed sequentially, they may instead be performed simultaneously or in different sequences. It is therefore intended that the following claims are interpreted to include all such variations as are within their intended scope.
Where a component (e.g. a software module, processor, assembly, device, circuit, etc.) is referred to above, unless otherwise indicated, reference to that component (including a reference to a “means”) should be interpreted as including as equivalents of that component any component which performs the function of the described component (i.e., that is functionally equivalent), including components which are not structurally equivalent to the disclosed structure which performs the function in the illustrated exemplary embodiments of the invention.
Specific examples of systems, methods and apparatus have been described herein for purposes of illustration. These are only examples. The technology provided herein can be applied to systems other than the example systems described above. Many alterations, modifications, additions, omissions, and permutations are possible within the practice of this invention. This invention includes variations on described embodiments that would be apparent to the skilled addressee, including variations obtained by: replacing features, elements and/or acts with equivalent features, elements and/or acts; mixing and matching of features, elements and/or acts from different embodiments; combining features, elements and/or acts from embodiments as described herein with features, elements and/or acts of other technology; and/or omitting combining features, elements and/or acts from described embodiments.
It is therefore intended that the following appended claims and claims hereafter introduced are interpreted to include all such modifications, permutations, additions, omissions, and sub-combinations as may reasonably be inferred. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.
This application claims priority from U.S. patent application No. 62/173,580 filed on 10 Jun. 2015 and U.S. patent application No. 62/205,594 filed on 14 Aug. 2015 both of which are hereby incorporated herein by reference for all purposes. For purposes of the United States of America, this application claims the benefit of U.S. patent application No. 62/173,580 filed on 10 Jun. 2015 and U.S. patent application No. 62/205,594 filed on 14 Aug. 2015.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/CA2016/050672 | 6/10/2016 | WO | 00 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2016/197255 | 12/15/2016 | WO | A |
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