Patent Application
20150000931
This section provides background information to facilitate a better understanding of the various aspects of the present invention. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.
A string of wellbore tubulars (e.g., pipe, casing, drillpipe, etc.) may weigh hundreds of thousands of pounds. Despite this significant weight, the tubular string must be carefully controlled as tubular segments are connected and the string is lowered into the wellbore and as tubular segments are disconnected and the tubular string is raised and removed from the wellbore. Fluidically (e.g., hydraulic and/or pneumatic) actuated tools, such as elevator slips and spider slips, are commonly used to make-up and run the tubular string into the wellbore and to break the tubular string and raise it from the wellbore. The elevator (e.g., string elevator) is carried by the traveling block and moves vertically relative to the spider which is mounted at the drill floor (e.g., rotary table). Fluidic (e.g., hydraulic and/or pneumatic) control equipment is provided to operate the slips in the elevator and/or in the spider. Examples of fluidically actuated slip assemblies (e.g., elevator slip assemblies and spider slip assemblies) and controls are disclosed for example in U.S. Pat. No. 5,909,768 which is incorporated herein by reference; and U.S. Pat. Appl. Pub. Nos. 2009/0056930 and 2009/0057032 of which this application is a continuation-in-part.
The tubular string is typically constructed of tubular segments which are connected by threading together. Traditionally, the top segment (e.g., add-on tubular) relative to the wellbore is stabbed into a box end connection of the tubular string which is supported in the wellbore by the spider. It is noted that the pin and box end may be unitary portions of the tubular segments (e.g., drillpipe) or may be provided by a connector (e.g., casing) which is commonly connected to one end of each tubular prior to running operations. In many operations, the threaded connection is then made-up or broken utilizing tools such as spinners, tongs and wrenches. One style of devices for making and breaking wellbore tubular strings includes a frame that supports up to three power wrenches and a power spinner each aligned vertically with respect to each other. Examples of such devices are disclosed in U.S. Pat. No. 6,634,259 which is incorporated herein by reference. Examples of some internal grip tubular running devices are disclosed in U.S. Pat. Nos. 6,309,002 and No. 6,431,626, which are incorporated herein by reference.
The tubular segments may be transported to and from the rig floor and alignment with the wellbore by various means including without limitation, cables and drawworks, pipe racking devices, and single joint manipulators. An example of a single joint manipulator arm (e.g., elevator) is disclosed in U.S. Pat. Appl. Publ. No. 2008/0060818, which is incorporated herein by reference. The disclosed manipulator is mounted to a sub positioned between the top drive and the tubular running device. A sub mounted manipulator (e.g., single arm, double arm, etc.) may be utilized with the device of the present disclosure.
It may be desired to fill (e.g., fill-up and/or circulate) the tubular string with a fluid (e.g., drilling fluid, mud) in particular when running the tubular string into the wellbore. In some operations it may be desired to perform cementing operations when running tubular strings, in particular casing strings. Examples of some fill-up devices and cementing devices are disclosed in U.S. Pat. Nos. 7,096,948; 6,595,288; 6,279,654; 5,918,673 and 5,735,348, all of which are incorporated herein by reference.
Tubular strings are often tapered, meaning that the outside diameter (OD) of the tubular segments differ along the length of the tubular string, e.g., have at least one outside diameter transition. Generally the larger diameter tubular sections are placed at the top of the wellbore and the smaller size at the bottom of the wellbore, although a tubular string may include transitions having the larger OD section positioned below the smaller OD section. Running tapered tubular strings typically requires that specifically sized pipe-handling tools (e.g., elevators, spiders, tongs, etc.) must be available on-site for each tubular pipe size. In some cases, the tubular, in particular casing, may have a relatively thin wall that can be crushed if excess force is applied further complicating the process of running tubular strings.
It is a desire, according to one or more aspects of the present disclosure, to provide a method and device for running a tapered tubular string into and/or out of a wellbore. It is a further desire, according to one or more aspects of the present disclosure, to provide a method and device that facilitates filling a tubular string with fluid during a tubular running operation.
A tubular running tool according to one or more aspects of the present disclosure includes a carrier connected to traveling block of a drilling rig; a body having a tapered surface, the body rotationally connected to the carrier; slips moveably disposed along the tapered surface for selectively gripping a tubular; and a rotational device connected to the slips, the rotational device selectively rotating the slips and gripped tubular relative to the carrier.
A method for running a tubular string in wellbore operations according to one or more aspects of the present disclosure includes providing a tubular running tool comprising gripping assembly rotationally connected to a carrier, the gripping assembly comprising a body and slips; connecting the carrier to a quill of a top drive of a drilling rig; positioning an end of a tubular for gripping with the slips; actuating the slips into gripping engagement with the tubular; and rotating the tubular with the slips in gripping engagement therewith.
According to one or more aspects of the present disclosure, a method for running a tubular string with at least one outer diameter transition into a wellbore includes suspending a tubular running device from a drilling rig, the tubular running device comprising a carrier, a body forming a bowl, the body rotationally connected to the carrier, slips moveably disposed in the bowl, an actuator for at least one of raising and lowering the slips relative to the bowl, and a rotational actuator for selectively rotating the slips; gripping a tubular string with a spider to suspend the tubular string in the wellbore, the tubular string having a first outside diameter; gripping a first add-on tubular with the slips of the tubular running device, the add-on tubular having a first outside diameter; threadedly connecting the add-on tubular to the tubular string; releasing the grip of the spider on the tubular string and suspending the tubular string in the wellbore from the tubular running device; lowering the tubular string into the wellbore by lowering the tubular running device toward the spider; engaging the spider into gripping engagement of the tubular string; releasing the tubular running device from the tubular string; gripping a second add-on tubular with the tubular running device, the second add-on tubular gripped at a location thereof having a second outside diameter different from the first outside diameter of the tubular string; and threadedly connecting the add-on tubular to the tubular string.
The foregoing has outlined some features and technical advantages of the present disclosure in order that the detailed description that follows may be better understood. Additional features and advantages will be described hereinafter which form the subject of the claims of the invention.
The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.
It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
As used herein, the terms “up” and “down”; “upper” and “lower”; “top” and “bottom”; and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements. Commonly, these terms relate to a reference point as the surface from which drilling operations are initiated as being the top point and the total depth of the well being the lowest point, wherein the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface. The terms “pipe,” “tubular,” “tubular member,” “casing,” “liner,” “tubing,” “drillpipe,” “drillstring” and other like terms can be used interchangeably.
In this disclosure, “fluidically coupled” or “fluidically connected” and similar terms (e.g., hydraulically, pneumatically), may be used to describe bodies that are connected in such a way that fluid pressure may be transmitted between and among the connected items. The term “in fluid communication” is used to describe bodies that are connected in such a way that fluid can flow between and among the connected items. Fluidically coupled may include certain arrangements where fluid may not flow between the items, but the fluid pressure may nonetheless be transmitted. Thus, fluid communication is a subset of fluidically coupled.
The present disclosure relates in particular to devices, systems and methods for making and/or breaking tubular strings and/or running tubular strings. For example devices, systems and methods for applying torque to a tubular segment and/or tubular string, gripping and suspending tubular segments and/or tubular strings (e.g., lifting and/or lowering), and rotating (e.g., rotating while reciprocating) tubular segments and/or tubular strings. According to one or more aspects of the present disclosure, a tubular gripping tool may include fill-up, circulating, and/or cementing functionality.
Depicted device 10 is connected to top drive 8 via quill 12 (e.g., drive shaft) which includes a bore for disposing fluid (e.g., drilling fluid, mud). In this embodiment, device 10 also comprises a thread compensator 14. Thread compensator 14 may be threadably connected between quill 12 and device 10, e.g., carrier 34 thereof. Additionally or alternatively, device 10 can be connected (e.g., supported) from bails 18, e.g., in an embodiment where the quill is not utilized to rotate device 10. Thread compensator 14 may provide vertical movement (e.g., compensation) associated with the travel distance of the add-on tubular when it is being threadedly connected to or disconnected from the tubular string. Examples of thread compensators include fluidic actuators (e.g., cylinders) and biased (e.g., spring) devices. For example, the thread compensator may permit vertical movement of the connected device 10 in response to the downward force and movement of add-on tubular 7a as it is threadedly connected to tubular string 5. One example of a thread compensator is disclosed in U.S. Pat. Appl. Publ. No. (Ser. No. 12/414,645), which is incorporated herein by reference.
Tubular running device 10 is depicted supporting a string 5 of interconnected tubular segments generally denoted by the numeral 7. The upper most or top tubular segment is referred to as the add-on tubular, denoted in
In
A single joint elevator 16 is depicted in
Power and operational communication may be provided to tubular running device 10 and/or other operating systems via lines 20. For example, pressurized fluid (e.g., hydraulic, pneumatic) and/or electricity may be provided to power and/or control one or more devices, e.g., actuators. In the depicted system, a fluid 22 (e.g., drilling fluid, mud, cement, liquid, gas) may be provided to tubular string 5 via mud line 24. Mud line 24 is generically depicted extending from a reservoir 26 (e.g., tank, pit) of fluid 22 via pump 28 and into tubular string 5 via device 10 (e.g., fluidic connector, fill-up device, etc.). Fluid 22 may be introduced to device 10 and add-on tubular 7a and tubular string 5 in various manners including through a bore extending from top drive 8 and the devices intervening the connection of the top drive to device 10 as well as introduced radially into the section/devices intervening the connection of top drive 8 and device 10. For example, rotary swivel unions may be utilized to provide fluid connections for fluidic power and/or control lines 20 and/or mud line 24. Swivel unions may be adapted so that the inner member rotates for example through a connection to the rotating quill. Swivel unions may be obtained from various sources including Dynamic Sealing Technologies located at Andover, Minn., USA (www.sealingdynamics.com). Swivel unions may be used in one or more locations to provide relative movement between and/or across a device in addition to providing a mechanism for attaching and or routing fluidic line and/or electric lines.
Gripping assembly 32 includes slips 42 and actuators 44. Although multiple actuators are depicted, a single actuator may be used to power the slips up and/or down relative to bowl 60. According to one or more aspects, actuators 44 may be hydraulic or pneumatic actuators to raise and/or lower slips 42 relative to bowl 60 (
A rotational driver 46, carried with running device 10, is connected to gripping assembly 32. For example, rotational driver 46 is connected to slips 42 via bowl 60 (
Various other devices, sensors and the like may be included although not described in detail herein. For example, a pipe end sensor 52 schematically depicted in
Referring to
Depicted surface 62 mates with the outer surface 64 of slips 42 to move slips 42 toward and away from axis “X” when slips 42 are translated vertically along longitudinal axis “X” (e.g., by actuators 44 and/or timing ring 45). Each slip 42, e.g., all slips, may be retained along a radial line extending from the longitudinal axis “X” of the device 10 for example via timing ring 45. For example, and with reference to
Body 58 is connected to traveling block 6 and/or top drive 8 (
Rotational drive assembly 50 (e.g., gears, belt, etc.) is depicted as connected to body 58 (e.g., gripping assembly 32) in
According to one or more aspects of the present disclosure, a method for running a tapered tubular string into a wellbore is now described with reference to
The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure. The scope of the invention should be determined only by the language of the claims that follow. The teem “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group. The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.
The present application is a continuation of, and therefore claims benefit under 35 U.S.C. §120 to, U.S. patent application Ser. No. 13/669,975, filed on Nov. 6, 2012, and also claims benefit to U.S. patent application Ser. No. 12/604,327, filed on Oct. 22, 2009, having issued as U.S. Pat. No. 8,327,928 on Dec. 11, 2012, and also claims the benefit of priority to U.S. Provisional Patent Application No. 61/107,565, filed on Oct. 22, 2008. U.S. patent application Ser. No. 12/604,327 is also a continuation-in-part of, and therefore claims benefit under 35 U.S.C. §120 to, U.S. patent application Ser. No. 12/126,072, filed on May 23, 2008, having issued as U.S. Pat. No. 7,992,634 on Aug. 9, 2011, and is a continuation-in-part of, and therefore claims benefit under 35 U.S.C. §120 to, U.S. patent application Ser. No. 11/846,169, filed on Aug. 28, 2007, having issued as U.S. Pat. No. 7,997,333 on Aug. 16, 2011. These priority applications are hereby incorporated by reference in their entirety herein.
| Number | Date | Country | |
|---|---|---|---|
| 61107565 | Oct 2008 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13669975 | Nov 2012 | US |
| Child | 14245404 | US | |
| Parent | 12604327 | Oct 2009 | US |
| Child | 13669975 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 12126072 | May 2008 | US |
| Child | 12604327 | US | |
| Parent | 11846169 | Aug 2007 | US |
| Child | 12126072 | US |
