Abstract: According to one implementation, a tool driving device includes a drill chuck, a motor, a casing and a vibrating mechanism. The drill chuck holds a drill. The motor is configured to rotate the drill chuck. The casing houses the motor. The vibrating mechanism is configured to periodically reciprocate the drill chuck relatively to the casing in a tool axis direction during rotation of the drill chuck. The vibrating mechanism is configured to distance the drill chuck from the casing at a first speed smaller than a second speed for bringing the drill chuck close to the casing.

Abstract: A rotary steerable system including a steering section having not more than one piston or not more than two pistons in a transverse cross-sectional plane of the steering section. The steering section includes two distribution flow passages each extending from a valve to a piston. A ratio of a distribution flow passage diameter to steering section diameter is at least 0.07. The distribution flow passages are contained within a central area of the steering section, with a ratio of a central area diameter to steering section diameter being 0.5 or less, preferably 0.4 or less. The steering section may include two pistons having center points that are separated by an angle greater than 120 degrees, preferably about 180 degrees. A duration for which only one of the sets of pistons is activated is greater than 110 degrees of rotation of a valve rotor, preferably greater than 150 degrees.

Abstract: A ball dropping tool includes an outer and inner body, side bore, ball and an actuator. The outer body has an axial bore extending between a first and second end of the outer body and forming a flow path. The inner body forms a bypass passage extending between a first and second end of the inner body. The side bore is defined by the inner body and is disposed at an angle relative to the axial bore of the outer body. The bypass passage is disposed in a portion of the flow path and is in communication with the side bore. The ball is disposed within the side bore. The actuator, disposed within the outer body, is movable between a retaining position wherein the ball is retained within the side bore and a release position wherein the ball is released from the side bore and into the bypass passage.

Abstract: An integrated piling tool with continuous drilling and circulation pouring includes a power connector, a circulation device, a drill assembly, a bottom clearing and a pouring mechanism. The circulation device includes a circulating drill barrel and a spiral piece, and it achieves cuttings removal continuously; the two ends of the circulating drill barrel are connected with the power connector and the drill assembly, respectively. The drill assembly includes a drill body, a connecting sleeve B, transmission parts, a drill tool holder and drilling teeth, and the drill assembly accomplish rock breaking and rotary excavation. The clearing mechanism includes a linkage and clearing blades to remove cuttings at bottom hole. The pouring mechanism includes pouring channels and control parts to achieve continuous concrete pouring. The invention provides a new integrated piling tool with continuous drilling and circulation pouring, which improves the efficiency of piling, circulation and pouring.

Abstract: A system and method for controlling the frequency or amplitude of vibrations during drilling of a well. A system for generating mechanical vibrations may generate a control signal to cause two plates to impact one another with a first frequency or amplitude. The frequency or amplitude may be selected to steer the direction of drilling. In addition, a second control signal may be generated to cause the two plates to impact with a second frequency or amplitude to steer the direction of drilling, such as when the wellbore has deviated from the target path of a well plan. The control signals may be associated with one or more geological formations.

Abstract: Systems and methods for producing controlled vibrations within a borehole. In one example, the system includes a movement mechanism and a controller. The movement mechanism is configured to enable translational movement of a first surface relative to a second surface to allow the first surface to impact the second surface to produce a plurality of beats. The frequency and amplitude of the beats may be selectively controlled by suppressing or dampening the beats. The controller is configured to selectively control an amplitude or frequency of the beats to encode information therein, where the amplitude of a beat may be selectively controlled by dampening or suppressing the impact of the first surface and the second surface.

Abstract: A propulsion tool for delivering a tubing into a subterranean well for performing a downhole operation includes a tool housing, the tool housing being a tubular shaped member. A connector system is operable to secure the propulsion tool to the tubing. A jet assembly extends from an internal cavity of the tool housing to an outside of the tool housing and is oriented in an uphole direction. A jet inner flow path is located within the tool housing. The jet inner flow path is oriented to selectively direct a flow of fluid from the tubing in a direction towards the jet assembly.

Abstract: An earth-boring tool may comprise at least one cavity formed in a face thereof. At least one retractable pad residing in the at least one cavity may be coupled to a piston located at least partially within the at least one cavity. Additionally, a valve may be positioned within the earth-boring tool and configured to regulate flow of an incompressible fluid in contact with the piston through an opening of a reservoir. A cartridge may comprise a barrel wall defining a first bore, and a piston comprising at least one retractable pad positioned at least partially within the first bore. The barrel wall and the piston may define a first reservoir within the first bore, and a valve may be positioned and configured to regulate flow through an opening to the first reservoir. Related methods and devices are also disclosed.

Abstract: Some embodiments include an apparatus for cutting a pile. In some embodiments, the apparatus includes a shaft module including a cylindrical shaft including a first cavity configured to receive the pile. In some embodiments, the apparatus also includes a cutting module coupled to the shaft module, the cutting module including a second cavity configured to receive the pile, clamps configured to clamp onto the pile, and a saw configured to cut the pile. In some embodiments, the apparatus also includes a drilling module coupled to the cutting module, the drilling module including blades to burrow into an earth surface.

Abstract: A bit jet enhancement tool comprises two or more separate flow paths, and each of the flow paths has multiple hollow chambers connected in series; each of the hollow chambers comprises a first constricted chamber with a fluid entry, a first expansion chamber located adjacent to the lower end of the first constricted chamber, a second constricted chamber with the upper end connected to the lower end of the first expansion chamber; a separate second expansion chamber connected to the lower ends of a plurality of the second constricted chambers; and a single port located adjacent to the lower end of the second expansion chamber.

Abstract: A technique facilitates directional drilling of boreholes. A steerable system has a plurality of actuator pistons slidably mounted in a mechanical structure. The mechanical structure comprises a radially inward portion containing ports to deliver a portion of drilling mud to the plurality of actuator pistons. The mechanical structure also has a radially outward portion positioned to define a main flow passage extending longitudinally through the steerable system between the radially inward portion and the radially outward portion of the mechanical structure.

Abstract: A threaded tubular connection includes a female threaded portion at a first tubular component end and a male threaded portion at a second tubular component end, the female threaded portion including a female thread, at least one female sealing surface on its inner peripheral surface, and at least one female axial abutment surface, the male threaded portion including a male thread, at least one male sealing surface on its outer peripheral surface, at least one axial abutment surface, and a lip disposed between the sealing surface and an axial abutment surface located at a free end of the threaded portion distant from the thread, the male thread being made up into the female thread such that at least one male axial abutment surface is in contact with at least one female axial abutment surface, at least one male sealing surface being in interference contact with at least one corresponding female sealing surface, the portion of the lip between the sealing surface and the axial abutment surface being radially dist

Abstract: In one aspect, an apparatus for drilling a wellbore into an earth formation is disclosed, which apparatus, according to one embodiment, may include a drill string configured to be conveyed into a wellbore, wherein an annulus is formed between the drill string and a wellbore wall, a first flow device configured to circulate a first fluid from an annulus to a bore of the drill string, and a second flow device positioned downhole of the first flow device, the second flow device configured to circulate a second fluid from the bore of the drill string to the annulus.

Abstract: Apparatus and method for boring into the earth near a Kudzu vine root system to apply herbicidal helium gas to the roots and eradicate the Kudzu vine. The technique uses a perforated tube with a drill bit that protrudes from one end of the tube to bore into the earth near the vine roots. Boring is stopped when all of the tube perforations are below the earth's surface. About 0.5 cubic meters of helium gas are applied to flow through the tube enabling the helium gas to flow out through the tube perforations and attack the Kudzu vine through the vine's root system.

Abstract: Actuation mechanisms for downhole assemblies in earth-boring applications may comprise a housing comprising an internal bore defining a flow path through the housing. An actuation member may be supported within the housing. A movable sleeve may be located within the internal bore and may be movable between a first position and a second position responsive to changes in flow rate of fluid flowing through the flow path. The movable sleeve may be biased toward the first position. The actuation member may be in an initial, pre-actuation position when the movable sleeve is initially located in the first position. The actuation member may be movable to a subsequent, pre-actuation position when the movable sleeve is located in the second position. The actuation member may be released from the actuation mechanism when the movable sleeve is returned to the first position.

Abstract: A drilling fluid delivery system for drilling boreholes with a drill bit, includes a primary flow circuit having a relatively high flow rate for transferring drilling fluid to and from the drill bit. The system also includes a secondary flow circuit having a relatively low flow rate for transferring drilling fluid to and from the primary flow circuit. Furthermore, the system includes a cuttings transfer system, such as a hydrocyclone or a rotating filter, between the primary and secondary flow circuits. When the cutting transfer system is in use, it receives fluid containing cuttings from the primary circuit and separates the fluid into a first stream that contains substantially no cuttings and a second stream containing cuttings. The first stream is returned to the primary flow circuit and the second stream is directed to the secondary flow circuit.

Abstract: A method for drilling a wellbore includes drilling the wellbore by injecting drilling fluid into a top of a tubular string disposed in the wellbore at a first flow rate and rotating a drill bit. The tubular string includes: the drill bit disposed on a bottom thereof, tubular joints connected together, a longitudinal bore therethrough, a port through a wall thereof, and a sleeve operable between an open position where the port is exposed to the bore and a closed position where a wall of the sleeve is disposed between the port and the bore. The method further includes moving the sleeve to the open position; and injecting drilling fluid into the port at a second flow rate while adding a tubular joint(s) to the tubular string. The injection of drilling fluid into the tubular string is continuously maintained between drilling and adding the joint(s).

Abstract: An apparatus including a stationary section having a first central fluid passage and operably connected to a drilling fluid inlet and a conduit, a rotating and reciprocating section having a second central fluid passage and operably connected to a tubular, wherein the rotating and reciprocating section reciprocates along a longitudinal axis and rotates in conjunction with the tubular and the conduit, and a third section having a third central fluid passage in fluid communication between the first and second central fluid passages, where the third section is operably disposed between the first and rotating and reciprocating sections to permit the rotating and reciprocating section to slide axially even during rotation and to permit only rotational motion at an end adjacent the stationary section.

Abstract: A head includes an outer cylindrical body with at least one upper inlet for fluids, at least one outlet side nozzle and at least one helical duct having a helical central line. The duct connects the upper inlet to the nozzle and imparts the fluid flowing through it a helical motion about the longitudinal axis of the outer body towards the nozzle. The helical duct is progressively tapered towards the nozzle and includes a terminal length of the duct which is radiused to the nozzle in a tapered manner, both when viewed in cross-sectional planes parallel to the longitudinal axis and tangent to the helical central line, as well as when viewed in cross-sectional planes perpendicular to the longitudinal axis.

Abstract: A flow restrictor comprising a body adapted to restrict a flow of fluid through a drill rod passage, the body having a coupling for coupling said body into the drill rod passage, said body defining an upstream fluid receiving passage, a downstream fluid egress passage, and a passage of restrictive diameter between said passages to limit the flow of fluid in the drill rod passage.

Abstract: An ejector pump or jet pump is for use in the drilling of wells in the underground for the production of oil and gas, for example, in which it is the purpose to prevent the total fluid pressure at the bottom of the borehole from reaching a level which constitutes a risk of cracking the rock or sediment being drilled, thus resulting in leakage and circulation failure. For this purpose, the pump is placed between the drill bit and the drill string by means of standard pipe couplings and formed as an elongated cylindrical element with external, longitudinal pump elements with nozzles directed in such a way that low pressure is established externally at the drill bit. The pump is operated by the drilling fluid which is supplied in the normal way from the drill string. The pressure difference across the pump is used to draw a secondary flow of drilling fluid from the established borehole through internal bores in the pump casing to the ordinary nozzles in the drill bit.

Abstract: Systems and methods to inhibit packoff during drilling assembly removal from a wellbore, utilizing a drilling assembly that includes a transition region between a first section having a first cross-sectional area and a second section having a second cross-sectional area, wherein the second cross-sectional area is greater than the first cross-sectional area. The transition region includes a fluidizing assembly configured to partially fluidize a portion of the cuttings bed that is proximal to the transition region, and/or be in fluid communication with a flow control assembly configured to control flow rate of a fluidizing stream from the fluidizing assembly and to the portion of cuttings bed.

Abstract: The present invention regards a method to be used when performing drilling in a well bore, comprising: positioning a dual bore drill pipe with a tool at on one end into a well bore, thereby forming an outer annulus between the well bore wall and the pipe and two inner bores within the pipe, dividing the outer annulus into two different sections along the longitudinal axis of the drill pipe, at least at one location close to the tool, providing a first fluid in the outer annuls and providing a second fluid within the drill pipe and around the tool, and a device.

Abstract: In one aspect of the present invention, a downhole drill string assembly comprises a bore there through to receive drilling fluid. A turbine may be disposed within the bore and exposed to the drilling fluid. At least one flow guide may be disposed within the bore and exposed to the drilling fluid wherein the flow guide acts to redirect the flow of the drilling fluid across the turbine. The flow guide may be adjusted by an actuator. Adjustments to the flow guide may be controlled by a downhole telemetry system, a processing unit, a control loop, or any combination thereof. In various embodiments the turbine may comprise rotatable turbine blades.

Abstract: The present invention relates methods and apparatus for lining a wellbore. In one aspect, a drilling assembly having an earth removal member and a wellbore lining conduit is manipulated to advance into the earth. The drilling assembly includes a first fluid flow path and a second fluid flow path. Fluid is flowed through the first fluid flow path, and at least a portion of which may return through the second fluid flow path. In one embodiment, the drilling assembly is provided with a third fluid flow path. After drilling has been completed, wellbore lining conduit may be cemented in the wellbore.

Abstract: Sleeves, stabilizers and other well tools may be formed with fluid flow paths or channels extending through one or more blades disposed on the exterior portions of such well tools. The blades and associated fluid flow paths extending therethrough may allow optimum fluid flow rates and volumes to enhance lifting of formation cuttings and downhole debris along with cleaning exterior portions of the well tool and an associated rotary drill bit. Location, configuration, orientation and/or dimensions associated with such blades and associated fluid flow paths or channels may also be modified to provide an enlarged pad or contact surface on exterior portions of one or more blades while maintaining desired fluid flow rates and volumes over exterior portions of the well tool. Such pads or contact surfaces may have optimum surface areas for contacting adjacent portions of a wellbore during directional drilling of the wellbore.

Abstract: A drilling composition is provided. The composition includes: I) an organic phase comprising components: i. from about 20 wt. % to about 99.999 wt. %, based on the total weight of components i. and ii., of at least one linear or branched, cyclic or non-cyclic, saturated hydrocarbon; ii. from about 0.001 wt. % to about 25 wt. %, based on the total weight of components i. and ii., of at least one ester; II) from 0 to about 50 wt. %, based on the total weight of the composition, of water or aqueous phase; III) from 0 to about 60 wt. %, based on the total weight of the composition, of at least one additive, wherein the sum of the weight components I) to III) is 100 wt. %.

Abstract: A rotating drill string sub redistributes wellbore drill cuttings into the drilling fluid flowstream to improve the efficiency of the drilling operation. Standoff elements are located on each side of an agitator, all configured on a relatively short section of drill pipe. The agitator comprises a plurality of alternating blades standing radially outward from and arranged helically about the axis of the sub, and grooves located between pairs of adjacent blades, each groove comprising a flow channel that is open at both ends of the agitator. The standoff elements contain abutment surfaces having an outer diameter greater than the outer diameter of the agitator, so that the agitator is prevented from contacting the wall of the wellbore and therefore does not experience the forces that the standoff elements experience.

Abstract: In one aspect of the present invention, a drill bit has a jack element that is substantially coaxial with an axis of rotation of the drill bit and the jack element has an asymmetrical distal end that extends beyond a working face of the drill bit. A turbine is located within a bore formed in the drill bit and a flow valve is actuated by the turbine. The flow valve is adapted to route a drilling fluid in the bore into a porting mechanism adapted to extend the jack element farther beyond the working surface of the drill bit. The turbine is also adapted to rotate the jack element at variable speeds.

Abstract: In one aspect of the present invention, a downhole drill string assembly comprises a bore there through to receive drilling fluid. A turbine may be disposed within the bore and exposed to the drilling fluid. At least one flow guide may be disposed within the bore and exposed to the drilling fluid wherein the flow guide acts to redirect the flow of the drilling fluid across the turbine. The flow guide may be adjusted by an actuator. Adjustments to the flow guide may be controlled by a downhole telemetry system, a processing unit, a control loop, or any combination thereof. In various embodiments the turbine may comprise rotatable turbine blades.

Abstract: A downhole tool comprises a body defining a fluid inlet and two or more fluid outlets. A valve arrangement cycles the proportion of fluid directed from the inlet to each of the outlets. One of the outlets may be associated with a fluid pressure responsive device, such as a cleaning blade.

Abstract: A downhole percussive tool is disclosed comprising an interior chamber and a piston element slidably sitting within the interior chamber forming two pressure chambers on either side. The piston element may slide back and forth within the interior chamber as drilling fluid is channeled into either pressure chamber. Input channels supply drilling fluid into the pressure chambers and exit orifices release that fluid from the same. An exhaust orifice allows additional drilling fluid to release from the interior chamber. The amount of pressure maintained in either pressure chamber may be controlled by the size of the exiting orifices and exhaust orifices. In various embodiments, the percussive tool may form a downhole jack hammer or vibrator tool.

Abstract: Exemplary embodiments provide systems and methods for minimizing erosion of a transmission cable extending through a downhole drilling assembly. The drilling assembly includes an elongated flow diverter having a plurality of apertures for diverting the drilling fluid from an axial flow through a transmission shaft to a radial flow through a drive shaft. Exemplary flow diverters are configured to minimize erosion of transmission cables that may be present adjacent to the flow diverters.

Abstract: The present invention relates to a drilling composition comprising: I) an organic phase comprising components: i. from about 20 wt. % to about 99.999 wt. %, based on the total weight of components i. and ii., of at least one linear or branched, cyclic or non-cyclic, saturated hydrocarbon; ii. from about 0.001 wt. % to about 25 wt. %, based on the total weight of components i. and ii., of at least one ester; II) from 0 to about 50 wt. %, based on the total weight of the composition, of water or aqueous phase; III) from 0 to about 60 wt. %, based on the total weight of the composition, of at least one additive, wherein the sum of the weight components I) to III) is 100 wt. %, to a process for preparation of a drilling composition, to uses of a drilling composition, to a drilling system, to a process for making a borehole, to a process for conveying cuttings, to a process for treating a drill head, to a process for production of at least one of oil and gas.

Abstract: The present invention relates methods and apparatus for lining a wellbore. In one aspect, a drilling assembly having an earth removal member and a wellbore lining conduit is manipulated to advance into the earth. The drilling assembly includes a first fluid flow path and a second fluid flow path. Fluid is flowed through the first fluid flow path, and at least a portion of which may return through the second fluid flow path. In one embodiment, the drilling assembly is provided with a third fluid flow path. After drilling has been completed, wellbore lining conduit may be cemented in the wellbore.

Abstract: One exemplary APD Device is used with a liner drilling assembly to control wellbore pressure. The APD Device reduces a dynamic pressure loss associated with the drilling fluid returning via a wellbore annulus. Another exemplary APD Device is used to control pressure in a wellbore when deploying wellbore equipment, including running, installing and/or operating wellbore tools. The APD Device is set to reduce a dynamic pressure loss associated with a circulating fluid. The APD Device can also be configured to reduce a surge effect associated with the running of the wellbore equipment. Still another APD Device is used to control pressure in a wellbore when completing or working over a well. Exemplary completion activity can include circulating fluid other than a drilling fluid, such as a gravel slurry. The APD Device can reduce the dynamic pressure loss associated with circulation of both drilling fluid and non-drilling fluid.

Abstract: A connection device for forming a fluid supply to a rotating tool, in which is provided a rotary feedthrough which has a rotor and a stator, the rotor being supported in a rotating manner relative to the stator. Furthermore, a torque support is provided, which is connected in a rotationally fixed manner to the stator and has at least one contact element. The at least one contact element can be displaced between a retracted position and a protruding position, in which the contact element is extended compared to the retracted position for the purpose of torque support.

Abstract: In one aspect of the invention, a downhole centrifugal drilling fluid separator has a bore within a tubular body comprising a central axis. The bore is formed to receive drilling fluid comprising particulate matter. At least one fin rigidly fixed within the bore and at least one port formed in a wall of the tubular body. As the drilling fluid flows through the tubular body the at least one fin creates a rotary motion within the drilling fluid forcing a portion of the particulate matter away from the central axis and through the at least one port in the tubular body.

Abstract: In one aspect of the invention, a downhole centrifugal drilling fluid separator has a bore within a tubular body comprising a central axis. The bore is formed to receive drilling fluid comprising particulate matter. At least one fin rigidly fixed within the bore and at least one port formed in a wall of the tubular body. As the drilling fluid flows through the tubular body the at least one fin creates a rotary motion within the drilling fluid forcing a portion of the particulate matter away from the central axis and through the at least one port in the tubular body.

Abstract: A tubular downhole tool string component having a sidewall with a fluid passageway formed therein between a first end and second end, and a valve mechanism disposed within the fluid passageway adapted to substantially cyclically build-up and release pressure within the fluid passageway such that a pressure build-up results in radial expansion of at least a portion of the sidewall and wherein a pressure release results in a radial contraction of the portion of the sidewall. The valve mechanism disposed within the fluid passageway comprises a spring. Radial expansion and contraction of the portion of the sidewall varies a weight loaded to a drill bit disposed at a drilling end of the drill string.

Abstract: The system and device described relates to flow pulsing for use in down-hole drilling rate of penetration (ROP) enhancement and measurement while drilling (MWD) using a pulse drilling device (PDD) with a fast acting valve in conjunction with a pilot valve to produce high pressure, high amplitude, low duration pressure pulses.

Abstract: An element for a drill string includes at least one zone bearing on a wall of the drilled hole, the bearing zone including at least one bearing section with an external diameter greater than the diameter of the other portions of the element, and two activation zones substantially adjacent to the bearing zone and disposed upstream and downstream of the bearing zone. The activation zones include a plurality of grooves with a generally helical shape about the axis of the element. The bearing zone includes two guide sections in a shape of a convex rounded body of revolution, disposed upstream and downstream of the bearing section in a manner adjacent to the bearing section, and tangential to the bearing section and to the activation zones.

Abstract: A system and method are provided for drilling a wellbore. The wellbore is formed with a drilling tool that cuts through a formation. A pumping system removes cuttings from the drilling tool and also transports the cuttings along at least a portion of the wellbore formed behind the drilling tool.

Abstract: A drilling system for use in a well bore consists of a drill string, an electrically powerable pump (8), a connector (16) for supporting the pump (8) including a through bore (32) through which fluid can flow, and a power cable (15) to provide power to the electrically powerable pump. The cuttings are pumped up through the drillpipe (3). The drill bit (4) may also be powered by the pump. Part of the cable is disposed externally to the drill string where new pipe sections are added, before passing into the drill string through a cross-over means (40) further down the drillpipe to connect to the electrically powerable pump.

Abstract: A drilling system comprising a pipe comprising a first end and a second end; a drill bit near a first end of the pipe, adapted to drill a hole in a formation; a pipe rotator near a second end of the pipe adapted to rotate the pipe; and a pump connected to the pipe between the first end and the second end, the pump adapted to transport a fluid from the first end of the pipe to the second end of the pipe, the pump comprising a first portion adapted to rotate with the pipe and a second portion adapted to remain stationary relative to the pipe.

Abstract: An APD Device provides a pressure differential in a wellbore to control dynamic pressure loss while drilling fluid is continuously circulated in the wellbore. A continuous circulation system circulates fluid both during drilling of the wellbore and when the drilling is stopped. Operating the APD Device allows wellbore pressure control during continuous circulation without substantially changing density of the fluid. The APD Device can maintain wellbore pressure below the combined pressure caused by weight of the fluid and pressure losses created due to circulation of the fluid in the wellbore, maintain the wellbore at or near a balanced pressure condition, maintain the wellbore at an underbalanced condition, reduce the swab effect in the wellbore, and/or reduce the surge effect in the wellbore. A flow restriction device that creates a backpressure in the wellbore annulus provides surface control of wellbore pressure.

Abstract: The present disclosure relates to a tunneling apparatus including a drill head having a main body and a drive stem rotatably mounted within the main body. The main body defines a vacuum passage offset from the drive stem that extends through the main body from a proximal end to a distal end of the main body. The tunneling apparatus also includes an axial bearing structure for transferring axial load between the drive stem and the main body of the drill head. The axial bearing structure is proximally offset from the distal end of the main body of the drill head. The tunneling apparatus further includes a first radial bearing structure for transferring radial load between the drive stem and the main body of the drill head. The first radial bearing structure is positioned between the axial bearing structure and the distal end of the main body of the drill head and is distally offset from the axial bearing structure.

Abstract: Provided is an excavation tool for efficiently taking waste rocks produced during excavation into the inner peripheral side of a casing pipe and discharging the waste rocks to the outside. An excavation tool (10) includes a casing shoe (11), a casing pipe (15), a rod (60), a device (40), and an excavation bit (20). A discharge flute (46) for discharging the waste rocks is formed in the outer peripheral surface of the device (40). The excavation bit (20) has a head portion (22) and a skirt portion (23). The device (40) can be inserted into the inner periphery of the skirt portion (23).

Abstract: In one aspect of the invention, a downhole tool string component comprises a fluid passageway formed between a first and second end. A valve mechanism is disposed within the fluid passageway adapted to substantially cyclically build-up and release pressure within the fluid passageway such that a pressure build-up results in radial expansion of at least a portion of the fluid passageway and wherein a pressure release results in a contraction of the portion of the fluid passageway. The valve mechanism disposed within the fluid passageway comprises a spring. Expansion and contraction of the portion of the fluid passageway varies a weight loaded to a drill bit disposed at a drilling end of the drill string.

Abstract: The present invention relates methods and apparatus for lining a wellbore. In one aspect, a drilling assembly having an earth removal member and a wellbore lining conduit is manipulated to advance into the earth. The drilling assembly includes a first fluid flow path and a second fluid flow path. Fluid is flowed through the first fluid flow path, and at least a portion of which may return through the second fluid flow path. In one embodiment, the drilling assembly is provided with a third fluid flow path. After drilling has been completed, wellbore lining conduit may be cemented in the wellbore.