Abstract: A fiber support arrangement for a downhole tool includes a tubular; at least one end ring positioning the tubular spaced radially from a downhole tool and lacking contact therewith; and a fiber supported at the tubular and method.

Abstract: A polycrystalline diamond abrasive element, particularly a cutting element, comprises a table of polycrystalline diamond bonded to a substrate, particularly a cemented carbide substrate, along a non-planar interface. The non-planar interface typically has a cruciform configuration. The polycrystalline diamond has a high wear-resistance, and has a region adjacent the working surface lean in catalysing material and a region rich in catalysing material. The region lean in catalysing material extends to a depth of 40 to 90 microns, which is much shallower than in the prior art. Notwithstanding the shallow region lean in catalysing material, the polycrystalline diamond cutters have a wear resistance, impact strength and cutter life comparable to that of prior art cutters, but requiring only 20% of the treatment times of the prior art cutters.

Abstract: A cutting element is provided including a substrate and a TSP material layer over the substrate. The TSP material layer includes at least a property having a value that varies through the layer.

Abstract: Ultra-hard constructions include an ultra-hard body having a first region including a polycrystalline matrix first phase and a second phase material interposed therein. The first region is substantially free of a catalyst material used to form the first phase. The body is formed by removing the catalyst material and then replacing it with the second phase material. A second region is disposed within the body and includes the polycrystalline matrix first phase and a catalyst material used to form the first phase. The second phase material has a thermal characteristic that is more closely matched to the matrix first phase than the catalyst material. The body may be joined to a substrate, and the ultra-hard body may consist entirely of the first region. The second phase material can include non-refractory metals, ceramics, silicon, silicon-containing compounds, diamond, cubic boron nitride, polycrystalline diamond, polycrystalline cubic boron nitride, and mixtures thereof.

Abstract: A seal assembly for sealing between a journal shaft and a rotating cone cutter of a drill bit. In an embodiment, the seal assembly comprises a seal gland positioned between the journal shaft and the cone cutter. In addition, the seal assembly comprises an annular seal body disposed about the journal shaft within an annular recess. The seal body comprises a dynamic sealing surface at its outer diameter D1 that forms a dynamic seal with the sealing surface of the recess and a static sealing surface at its inner diameter D2 that forms a static seal with an outer bearing surface of the journal shaft.

Abstract: A system for positioning a wellbore tool in a wellbore intersecting a subterranean formation includes a tag embedded in the formation using a tag insertion device. The tag may be configured to transmit a signal that includes information. A wellbore tool may utilize a tag detection device to operatively link with the tag. This operative link may provide an indication of the relative position of the tag detection device or some other information.

Abstract: An apparatus, method, and system for actuating a wellbore tool includes a body having a chamber in which a movable member is disposed. The movable member may connect to a selected wellbore tool. Within the chamber is a controllable fluid that substantially prevents relative movement between the body and the movable member when exposed to an applied magnetic field. A generator applies the magnetic field to the fluid and may change the applied magnetic field in response to a first control signal to release the movable member from the body. A driver displaces the movable member relative to the body once the movable member is released from the body.

Abstract: A cutting tool that includes at least one tungsten carbide cutting element disposed on a support, wherein at least one tungsten carbide cutting element has at least one localized region having a material property different from the remaining region, wherein the at least one localized region having a different material property is prepared by a method including determining at least one localized region needing a variation in a material property different from the remaining region; coating a portion of a surface of the at least one tungsten carbide cutting element with a refractory material such that a surface corresponding to the localized region is left uncoated; and treating the coated cutting element with a selected agent to diffuse the selected agent into the localized region is disclosed.

Abstract: A method for gripping a tubular with a tubular gripping mechanism includes the steps of moving the tubular gripping mechanism adjacent the tubular, positioning a jaw assembly of the tubular gripping mechanism around the tubular, applying a force by an actuator onto the jaw assembly of the tubular gripping mechanism such that the jaw assembly moves so as to clamp onto the tubular, removing the force from the actuator onto the jaw assembly such that the jaw assembly remains clamped onto the tubular. The clamping force is directed to surfaces of the tubular gripping mechanism away from the actuator.

Abstract: A method of determining the inflow profile of an injection wellbore, comprising stopping injection of fluid into a formation, the formation intersected by a wellbore having a section uphole of the formation and a section within the formation, monitoring temperature at least partially along the uphole section of the wellbore and at least partially along the formation section of the wellbore, injecting fluid into the formation once the temperature in the uphole section of the wellbore increases, and monitoring the movement of the increased temperature fluid as it moves from the uphole section of the wellbore along the formation section of the wellbore. The monitoring may be performed using a distributed temperature sensing system.

Abstract: A rotary steerable tool (2) for use in a downhole drilling apparatus for adjusting the direction of drilling is disclosed. The tool comprises a tubular outer housing (20) and a row of steering pushers (24) slidably mounted to the housing for movement between an extended position, in which the steering pusher engages a wall of a borehole formed by the drilling apparatus, and a withdrawn position, in which the steering pushers do not engage the wall of the borehole. A tubular sleeve (4) is mounted inside the housing (20) to transmit rotary drive to a drilling bit. A pressure chamber (22) defined between the sleeve (4) and the housing (20) communicates with the steering pushers (24) to move the steering pushers (24) to the extended position.

Abstract: Provided are methods that include a method comprising: placing a clean fluid comprising proppant particulates into a portion of a fracture in a subterranean formation, and depositing one or more of the proppant particulates into the fracture to form a partial monolayer. In another aspect, the invention provides methods that include placing a degradable fluid loss additive comprising collagen into a subterranean formation.

Abstract: 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.

Abstract: A swellable packer construction for continuous or segmented tubing. A method of constructing a swellable packer on a continuous tubular string includes the steps of: attaching a swellable seal material to the tubular string to thereby form the packer; and then wrapping the tubular string with the packer on a spool. A swellable packer includes a tubular body portion for incorporation into a tubular string, and a seal material wrapped about the body portion, the seal material being swellable in response to contact with a fluid. A method of constructing a swellable packer for a tubular string includes the steps of: wrapping a seal material about a tubular body portion to thereby form the packer; and then swelling the seal material in response to contact with a fluid. A continuous tubular string includes a seal material attached to a body portion of the tubular string to thereby form a swellable packer; and the packer wrapped with the tubular string on a spool.

Abstract: A technique is provided for processing well fluid downhole. The technique utilizes equipment for separating a well fluid downhole into a water component and an oil component. The separation of water and oil can be controlled by selecting an appropriately sized flow restrictor for use in limiting the flow of one or both of the water and the oil. Additionally, a sensor system is used to monitor a well characteristic that enables adjustment of the downhole fluid processing based on well characteristic data from the sensor system.

Abstract: One embodiment provides an adjustable guide 10a to steer the end 90 of a pipe string 88 into position to be engaged and supported by a pipe gripping apparatus such as, for example, an externally gripping elevator assembly 10. The adjustable guide 10a may comprise a plurality of angularly distributed guide inserts 30, each having a sloped surface 30A to engage a pipe end 90. Another embodiment provides an adjustable guide 60a to steer a pipe connection into position to pass through a spider 60. The guide inserts 30, 80 of an adjustable guide may be controllably positionable to together form a guide that is concentric with the bore of the tapered bowl of an elevator assembly or a spider. One embodiment comprises a guide insert retainer 11 having a plurality of channels 28, each slidably receiving a guide insert 30 and positionable by rotation of a threaded shaft 40.

Abstract: The present invention is directed to a segmented bottom guide for directing the top of a tubular member into and through a bore in the bottom of a tapered bowl so that the tubular member can be engaged by pipe slips. One embodiment of the segmented bottom guide of the present invention comprises a bottom guide retainer having a plurality of chambers for being disposed intermediate the top of a bell guide and the bottom of the tapered bowl. The bottom guide segments are radially received into, and securable in, the retainer to therein and together form a generally conical frustum generally aligned with and intermediate the top of the bell guide and the opening of the tapered bowl.

Abstract: The present invention involves methods and apparatus for permanent downhole deployment of optical sensors. Specifically, optical sensors may be permanently deployed within a wellbore using a casing string. In one aspect, one or more optical sensors are disposed on, in, or within the casing string. The optical sensors may be attached to an outer surface of the casing string or to an inner surface of the casing string, as well as embedded within a wall of the casing string. The optical sensors are capable of measuring wellbore parameters during wellbore operations, including completion, production, and intervention operations.

Abstract: A fluid flow control apparatus includes a flow path that conveys the fluid into a wellbore tubular, a first passage formed along the flow path, an annular space receiving the fluid from the first passage, and a second passage receiving fluid from the annular space. The passages may flow the fluid in an axial direction along the flow path. The apparatus may include an enclosure that receives a sleeve in which the passages are formed. The annular space may be formed between the sleeve and the enclosure. The passages may include an inlet that reduces a pressure of the fluid flowing through the inlet. The passages may include a bore and may include parallel conduits. The first and the second passages may convey the fluid in a first axial direction, and the annular space may be configured to convey the fluid in a direction opposite to the first axial direction.

Abstract: One embodiment provides an adjustable guide 10a to steer the end 90 of a pipe string 88 into position to be engaged and supported by a pipe gripping apparatus such as, for example, an externally gripping elevator assembly 10. The adjustable guide 10a may comprise a plurality of angularly distributed guide inserts 30, each having a sloped surface 30A to engage a pipe end 90. Another embodiment provides an adjustable guide 60a to steer a pipe connection into position to pass through a spider 60. The guide inserts 30, 80 of an adjustable guide may be controllably positionable to together form a guide that is concentric with the bore of the tapered bowl of an elevator assembly or a spider. One embodiment comprises a guide insert retainer 11 having a plurality of channels 28, each slidably receiving a guide insert 30 and positionable by rotation of a threaded shaft 40.