专利检索_ .磨损防护器;扶正装置例如稳定器专利检索_ .磨损防护器;扶正装置例如稳定器专利检索查询

子分类：

序号	专利名	申请号	申请日	公开（公告）号	公开（公告）日	发明人
141	Overpull Indicator	US12913553	2010-10-27	US20120103597A1	2012-05-03	Sibu Varghese; Ryan Herbel; Dien Nguyen; Javier Garcia
An outer wellhead member has a bore with a first profile portion and an annular recess. A tubular inner wellhead member with a centralizer/overpull ring is lowered into the outer wellhead member. The centralizer/overpull ring is biased to expand outward to engage the bore of the outer wellhead member to center the inner wellhead member within the bore as the inner wellhead member is lowered through the bore. The recess of the outer wellhead member is adapted to receive the centralizer/overpull ring and oppose axial movement of the centralizer/overpull ring to enable an upward test pull of the inner wellhead member.
142	Downhole apparatus with a swellable support structure	US13035644	2011-02-25	US08151894B2	2012-04-10	Kim Nutley; Brian Nutley
A downhole apparatus having a radially expanding portion and a support structure are described. The support structure comprises an attachment means for coupling to the apparatus and a support portion configured to be deployed from a first unexpanded condition to a second expanded condition by expansion of the apparatus. In one aspect of the invention, the downhole apparatus is expanded by exposing the swellable material to at least one predetermined fluid, and the support structure abuts the swellable material in its expanded form. A method of use and its application to a well packer, a hanging member, an anchor and a centralising apparatus are described.
143	ORIENTABLE ECCENTRIC DOWNHOLE ASSEMBLY	US12892289	2010-09-28	US20120073835A1	2012-03-29	Michael Hui Du; Kevin Beveridge
An assembly employing multiple eccentric devices about a mandrel. The assembly is configured such that at least one of the eccentric devices is adjustably orientable relative another. Thus, for example, where the devices are packers disposed about completions tubing, the adjustable orientation may be utilized to ensure enough clearance is available for downhole advancement of the assembly. As such, the assembly may remain eccentric in nature without concern over damage during positioning, particularly to a communication line running to actuatable implements of equipment coupled to the completions assembly.
144	ELECTRIC SUBMERSIBLE PUMP, TUBING AND METHOD FOR BOREHOLE PRODUCTION	US13147340	2010-01-28	US20120024543A1	2012-02-02	Philip Head
An electric submersible pump assembly (ESP) (21, 120) is deployed in a production tube (20, 100) in a borehole such that the motor (26, 41, 121) of the ESP is spaced from the inner wall of the production tube, defining a conduit (36, 111) through which the pumped well fluid can flow to cool the motor. The production tube may have an enlarged diameter portion (25, 76, 101) within which the motor is positioned. Alternatively or additionally, the ESP and/or the production tube may be provided with stabilising spacers (24, 45, 140, 141) which extend between the ESP and the tube to centralise the ESP in the tube and support it against vibrational movement, the spacers defining an annular conduit (36, 111) between the motor casing and the production tube.
145	Wellbore Centralizer for Tubulars	US12831770	2010-07-07	US20120006533A1	2012-01-12	Jason J. Barnard; Donald N. Horner; Michael H. Johnson
A tubular centralizer is secured to the tubular for run in. The profile for run in is small so that damage to the centralizer is minimized during run in. When the string is in position the centralizer is actuated to change shape or volume to engage the surrounding borehole to centralize the tubular for subsequent operations such as cementing or in the case of screens for gravel packing. The centralizer can be a shape memory material that is initially compressed at above its transition temperature to hold the smaller shape. At the desired location after run in it is brought above the transition temperature and changes back to the original shape or volume to centralize the tubular string. The structure can be spaced ring segments or a cohesive ring structure with an undulating profile or radiating blades to create flow spaces in the annulus where it is deployed for flow of a sealing material or gravel, for example.
146	Shearing tool and methods of use	US13136035	2011-07-21	US20110278020A1	2011-11-17	James Edward Chambers, II; Gerald Robert Byrd
A shearing tool for shearing, trimming, or reducing objects being pulled through a drill string and methods for retrieving retrievable tools with fins from the drill string, where the retrievable tools must pass through restrictions in the drill string having interior diameters less than the outer diameters of the fins. The fins, affixed to the retrievable tools, provide stability to the tools, while within the drill string, and can be made of rubber, plastic, other shearable materials, or combinations thereof. The apparatuses and methods include inserting a shearing tool with a flange into a box end of a section of drill string, where the flange keeps the shearing tool in place. The shearing tool further comprising a cutting surface for cutting materials pulled through the shearing tool.
147	Expandable Centralizer For Expandable Pipe String	US13019084	2011-02-01	US20110186289A1	2011-08-04	Jean Buytaert; Eugene Edward Miller; Donald Elwin McDowell
A close-tolerance expandable bow spring centralizer 8 having a first expandable collar 10A coupled to and spaced apart from a second expandable collar 10B through a plurality of bow springs 30 wherein expandable collars 10A, 10B comprise a plurality of slidably coupled links 16 that separate to expand the diameter of the collars 10A, 10B, e.g., upon expansion of an expandable pipe string 80 on which the centralizer 8 is received. Expandable bow spring centralizer 8 may grip the expandable pipe string 80 when in the collapsed configuration to eliminate the need for a stop collar. Additionally or alternatively, a fin 32 may be connected to each bow spring 30, and then connected to one or more adjacent fins 32 upon collapse of the bow springs 30 to form a restraining band 39 that may be ruptured, e.g., upon expansion of the expandable pipe string 80.
148	Glass Forming Hardbanding Material	US12917343	2010-11-01	US20110100720A1	2011-05-05	Daniel James BRANAGAN; Brian E. MEACHAM; William D. KIILUNEN; James N. MILLOWAY; Brian D. MERKLE
A drill pipe and a method of applying hardbanding thereto. A hardbanding alloy comprising iron and manganese present in the range of 67 to 87 weight percent (wt. %), niobium and chromium present in the range of 9 to 29 wt. %, and boron, carbon and silicon present in the range of 3 to 6.5 wt. % may be welded around at least a portion of a tool joint circumference. The hardbanding alloy may exhibit a hardness of 45 Rc to 70 Rc and a wear rate in the range of 0.08 grams to 1.60 grams of mass loss after 6,000 cycles as measured using ASTM G65-04, Procedure A.
149	Downhole apparatus with a swellable connector	US12470401	2009-05-21	US07784550B2	2010-08-31	Kim Nutley; Brian Nutley
A kit of parts which is assembled to form downhole apparatus comprises a swellable member, which expands upon contact with at least one predetermined fluid, and a connector. The swellable member has a first mating profile towards a first end and a second mating profile towards a second, opposing end. The connector has a mating profile configured to mate with each of the first and second mating profiles of the swellable member. The connector can therefore be connected to either the first and second ends of the swellable member. The connector may be an end connector, or may connect the swellable member to a second swellable member. In either case, the connector may define an arresting surface against which the swellable member abuts when expanding. The kit of parts can be adapted to and installed on any well tubular, and may form any of a variety of tools.
150	Apparatus and methods to perform downhole measurements associated with subterranean formation evaluation	US11694463	2007-03-30	US07600420B2	2009-10-13	Dale Meek
A system for testing an underground formation penetrated by a well includes a downhole tool that is configured to be coupled to a work string and that includes an outer surface, a connection for coupling a stabilizing sub to the downhole tool, and at least one portion configured to receive a frame. The system further includes a plurality of stabilizing subs that are configured to be coupled to the downhole tool, a plurality of frames configured to be detachably mounted on the at least one portion of the downhole tool, and at least one measuring device configured to be secured in at least one of the plurality of frames. The stabilizing subs each have an outer surface that defines an offset relative to the outer surface of the downhole tool, wherein a first of the plurality of stabilizing subs has a first stabilizing sub offset, and the plurality of frames each have an offset relative to the outer surface of the downhole tool and an aperture for receiving a measuring device, wherein a first of the plurality of frames has a first frame offset determined by the first stabilizing sub offset.
151	Apparatus and methods to perform downhole measurements associated with subterranean formation evaluation	US11755231	2007-05-30	US07581440B2	2009-09-01	Dale Meek; Julian J. Pop; Robert W. Sundquist; Alain P. Dorel; Thomas D. MacDougall
A system for testing a subterranean formation penetrated by a well includes a downhole tool configured to be coupled to a work string that includes a tool body having a longitudinal bore for circulating a fluid and at least one aperture configured to receive at least one module. The system further includes a plurality of modules that are each configured to engage the at least one aperture and at least one cavity configured for receiving a probe, and a plurality of probes that each include at least one orifice configured for testing the formation, wherein a first of the plurality of probes has a first configuration and a second of the plurality of probes has a second configuration.
152	Method for retrofitting a downhole drill string with a flow through subassembly and method for making same	US12321611	2009-01-23	US20090133883A1	2009-05-28	Jeffery D. Baird
A method for retrofitting a downhole drill string with a flow through subassembly having a hollow outer body or barrel with a plurality of outwardly extending blades. Fluid flow inlets are provided in the lower section of the body below the blade openings and flow outlets are provided in an upper section above the blades. A fluid flow bypass channel is formed in the outer body and extends between said blades and from said fluid inlet to said fluid outlet. Drilling fluids outside of the subassembly may flow through the inlet, up the fluid flow bypass channel and out the outlet thereby bypassing any plug or pack-off formed between the subassembly and the well bore. Thus, an existing subassembly may be retrofitted to provide a fluid flow bypass channel around the blades.
153	Thread fatigue relief for tool joint	US11642422	2006-12-20	US07490663B2	2009-02-17	Evan G. Lewis; Mohan L. Soni
A bottom hole assembly used for making a window in a tubular is modified to reduce tool joint stress in a connection above the topmost watermelon mill. A protrusion is located between the topmost watermelon mill and the next threaded joint uphole. Preferably, the protrusion height is not greater than the outside dimension of the largest watermelon mill. Preferably, the protrusion is located below the upset area in the tubular where the threaded joint is made up and about ⅓ the distance downhole from the threads to the next adjacent watermelon mill.
154	Arm for moving flexible lines at a wellsite	US11903058	2007-09-20	US20080006400A1	2008-01-10	William Coyle
A movable arm 10 engages a flexible line 50 at a well site for positioning the flexible line between run-in position for passing the flexible line with a tubular through a well hole in the rig floor and a clamping position wherein the flexible line is adjacent the tubular above the rig floor for clamping the line to the tubular. The arm 10 extends upward from the rig floor 70, and includes a line guide, such as roller 12, for engaging the flexible line when in the run-in position. A powered drive 14 moves the arm between the run-in position and the clamping position. A spacer 82 may be used for positioning two or more flexible lines at a desired spacing relative to one another prior to positioning the lines within a clamp secured to the tubular. A slip bowl assembly 60 may be laterally movable so that slips do not engage the flexible line as it is run in the well.
155	Well communication system	US10431284	2003-05-07	US07222676B2	2007-05-29	Dinesh R. Patel; Rodney J. Wetzel; Peter V. Howard; Patrick W. Bixenman
A well system utilizes a control line system. The control line system is implemented with a completion of the type deployed in a wellbore. The control line system facilitates transmission of monitoring, command or other types of control and telemetry. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. 37 CFR 1.72(b).
156	Wear resistant tubular connection	US11549007	2006-10-12	US20070074868A1	2007-04-05	MAURICE SLACK; Robert Tessari; Per Angman; Tommy Warren
A wear resistant casing connection including a wear resistant portion on its exterior surface is taught. A casing connection having a controlled bend angle is also taught.
157	Drill string element having at least one bearing zone, a drill string, and a tool joint	US10777768	2004-02-13	US07182160B2	2007-02-27	Jean Boulet
The drill string element has at least one bearing zone for bearing against the wall of the borehole during drilling. The bearing zone comprises at least one bearing segment extending in the axial direction and having an outside surface that is cylindrical and of constant diameter greater than the diameter of any other portion of the surface of the element, and also having a guide zone that is circularly symmetrical about the axis of the drill string element. The bearing zone preferably also has a drilling fluid activation zone extending axially in a disposition adjacent to the bearing segment. The guide zone presents a radius of curvature not less than one-third the outside diameter of the bearing segment. The outside surface of the intermediate activation zone presents a meridian having a first meridian portion and a second meridian portion situated downstream from the first meridian portion, the meridian portions being inclined in opposite directions relative to the axis, sloping towards the axis and being connected together by a minimum-diameter portion of the bearing zone.
158	Stab Guide	US11161316	2005-07-29	US20070023190A1	2007-02-01	David Hall; James McPherson; Patrick Hannigan
A tool string stab guide for axially aligning first tool string components with second tool string components is disclosed. The stab guide has a body with an axial length along a longitudinal axis with a first and a second section. The first section of the body adapted for removable attachment within a diameter of a bore of a tool string component. The second section of the body has a centering element with a flow channel. The ratio of the axial length to the diameter is at least 2:1.
159	Downhole rotatable-shaft connector assembly and method	US10873606	2004-06-22	US07104345B2	2006-09-12	Jay Milton Eppink
A connector assembly for connecting with a rotatable shaft is provided. The connector assembly includes a mating sleeve threadably coupleable about the shaft and a center sleeve sized and shaped for deployment between the shaft and the mating sleeve. The center sleeve includes pluralities of splines formed on inner and outer surfaces thereof. The splines on the inner surface of the center sleeve are engageable with splines on the outer surface of the shaft and the splines on the outer surface of the center sleeve are engageable with splines on the inner surface of the mating sleeve. Exemplary embodiments of this invention are useful in downhole tools to reduce make-up torque requirements of the mating sleeve, and therefore may advantageously increase the cyclic torsional and/or bending load capacity of the shaft, while also increasing the total torsional load capacity of the connection.
160	Arm for moving flexible lines at a well site	US10982861	2004-09-24	US20060065404A1	2006-03-30	Dennis Pennison; William Coyle
A movable arm 10 engages a flexible line 50 at a well site for positioning the flexible line between run-in position for passing the flexible line with a tubular through a well hole in the rig floor and a clamping position wherein the flexible line is adjacent the tubular above the rig floor for clamping the line to the tubular. The arm 10 extends upward from the rig floor 70, and includes a line guide, such as roller 12, for engaging the flexible line when in the run-in position. A powered drive 14 moves the arm between the run-in position and the clamping position. A spacer 82 may be used for positioning two or more flexible lines at a desired spacing relative to one another prior to positioning the lines within a clamp secured to the tubular. A slip bowl assembly 60 may be laterally movable so that slips do not engage the flexible line as it is run in the well.

3 4 5 6 7 8 9 10 11 12

该功能需要专业版企业版VIP权限，您可以：