Patent Description:
Wellbores or wells (also referred to as boreholes) are drilled in subsurface formations for the production of hydrocarbons (oil and gas) using a drill string that includes a drilling assembly (commonly referred to as a "bottomhole assembly" or "BHA") attached to a drill pipe bottom. A drill bit attached to the bottom of the drilling assembly is rotated by rotating the drill string from the surface and/or by a drive, such as a mud motor, in the drilling assembly. A common method of drilling curved sections and straight sections of wellbores (directional drilling) utilizes a fixed bend (also referred to as adjustable kick-off or "AKO") mud motor to provide a selected bend or tilt to the drill bit to form curved sections of wells. To drill a curved section, the drill string rotation from the surface is stopped, the bend of the AKO is directed into the desired build direction and the drill bit is rotated by the mud motor. Once the curved section is complete, the drilling assembly, including the bend, is rotated from the surface to drill a straight section. Such methods produce uneven boreholes. The borehole quality degrades as the tilt or bend is increased, causing effects like spiraling of the borehole. Other negative borehole quality effects attributed to the rotation of bent assemblies include drilling of over-gauge boreholes, borehole breakouts, and weight transfer. Such apparatus and methods also induce high stress and vibrations on the mud motor components compared to drilling assembles without an AKO and create high friction between the drilling assembly and the wellbore due to the bend contacting the inside of the wellbore as the drilling assembly rotates. Consequently, the maximum build rate is reduced by reducing the angle of the bend of the AKO to reduce the stresses on the mud motor and other components in the drilling assembly. Such methods result in additional time and expenses to drill such wellbores. Therefore, it is desirable to provide drilling assemblies and methods for drilling curved wellbore sections and straight sections without a fixed bend in the drilling assembly to reduce stresses on the drilling assembly components and utilizing various downhole sensors control drilling of the wellbore.

The disclosure herein provides apparatus and methods for drilling a wellbore, wherein the drilling assembly includes a deflection device that allows (or self-adjusts) a lower section of the drilling assembly connected to a drill bit to tilt or bend relative to an upper section of the drilling assembly when the drilling assembly is substantially rotationally stationary for drilling curved wellbore sections and straightens the lower section of the drilling assembly when the drilling assembly is rotated for drilling straight or relatively straight wellbore sections. Various sensors provide information about parameters relating to the drilling assembly direction, deflection device, drilling assembly behavior, and/or the subsurface formation that is the drilling assembly drills through that may be used to drill the wellbore along a desired direction and to control various operating parameters of the defection device, drilling assembly and the drilling operations. <CIT> discloses a prior art apparatus having the features of the preamble of claim <NUM>. <CIT>, <CIT>, <CIT> and <CIT> disclose drilling apparatuses of the prior art.

In one aspect, an apparatus for drilling a directional wellbore is provided according to claim <NUM>.

In another aspect, a method for drilling a directional wellbore is provided according to claim <NUM>.

Examples of the more important features of a drilling apparatus have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are additional features that will be described hereinafter and which will form the subject of the claims.

For a detailed understanding of the apparatus and methods disclosed herein, reference should be made to the accompanying drawings and the detailed description thereof, wherein like elements are generally given same numerals and wherein:.

In aspects, the disclosure herein provides a drilling assembly or BHA for use in a drill string for directional drilling (drilling of straight and curved sections of a wellbore) that includes a deflection device that initiates a tilt to enable drilling of curved sections of wellbores and straightens itself to enable drilling of straight (vertical and tangent) sections of the wellbores. Such a drilling assembly allows drilling of straight sections when the drilling assembly is rotated and allows drilling of curved sections when the drilling assembly is stationary while the drill bit is rotated with the downhole drive. In aspects, directional drilling is achieved by using a self-adjusting "articulation j oint" (also referred to herein as a "pivotal connection", "hinge device" or "hinged" device) to allow a tilt in the drilling assembly when the drill string and thus the drilling assembly is stationary and optionally using a dampener to maintain the drilling assembly straight when the drilling assembly is rotated. In other aspects a force application device, such as a spring or a hydraulic device, may be utilized to initiate or assist the tilt by applying a force into a hinged direction. In another aspect, the hinge device or hinged device is sealed from the outside environment (i.e., drilling fluid flowing through the drive, the wellbore, and/or the wellbore annulus). The hinge, about which a lower section of the drilling assembly having a drill bit at the end thereof tilts relative to an upper section of the drilling assembly, maybe sealed to exclude contaminants, abrasive, erosive fluids from relatively moving members. The term "upper section" of the drilling assembly is means the part of the drilling assembly that is located uphole of the hinge device and the term "lower section" of the drilling assembly is used for the part of the drilling assembly that is located downhole of the hinge device. In another aspect, the deflection device includes a stop that maintains the lower section at a small tilt (for example, about <NUM> degree or greater) to facilitate initiation of the tilt of the lower section relative to the upper section when the drill string is stationary. In another aspect, the stop may allow the lower section to attain a straight position relative to the upper section when the drill string is rotated. In another aspect, the deflection device incudes another stop that defines the maximum tilt of the lower section relative to the upper section. The drilling system utilizing the drilling assembly described herein further includes one or more sensors that provide information or measurements relating to one or more parameters of interest, such as directional parameters, including, but not limited to, tool face inclination, and azimuth of at least a part of the drilling assembly. The term "tool face" is an angle between a point of interest such as a direction to which the deflection device points and a reference. The term "high side" is such a reference meaning the direction in a plane perpendicular about the tool axis where the gravitation is the lowest (negative maximum). Other references, such as "low side" and "magnetic north" may also be utilized. Other embodiments may include: sensors that provide measurements relating to the tilt and tilt rate in the deflection device; sensors that provide measurement relating to force applied by the lower section onto the upper section; sensors that provide information about behavior of the drilling assembly and the deflection device; and devices (also referred to as energy harvesting devices) that may utilize electrical energy harvested from motion (e.g. vibration) in the deflection device. A controller in the drilling assembly and/or at the surface determines one or more parameters from the sensor measurements and may be configured to communicate such information in real time via a suitable telemetry mechanism to the surface to enable an operator (e.g. an automated drilling controller or a human operator) to control the drilling operations, including, but not limited to, selecting the amount and direction of the tilt of the drilling assembly and thus the drill bit; adjusting operating parameters, such as weight applied on the drilling assembly, and drilling fluid pump rate. A controller in the drilling assembly and/or at the surface also may cause the drill bit to point along a desired direction with the desired tilt in response to one or more determined parameters of interest.

In other aspects, a drilling assembly made according to an embodiment of the disclosure: reduces wellbore spiraling, reduces friction between the drilling assembly and the wellbore wall during drilling of straight sections; reduces stress on components of the drilling assembly, including, but not limited to, a downhole drive (such as a mud motor, an electric drive, a turbine, etc.), and allows for easy positioning of the drilling assembly for directional drilling. For the purpose of this disclosure, the term stationary means to include rotationally stationary (not rotating) or rotating at a relatively small rotational speed (rpm), or angular oscillation between maximum and minimum angular positions (also referred to as "toolface fluctuations"). Also, the term "straight" as used in relation to a wellbore or the drilling assembly includes the terms "straight", "vertical" and "tangent" and further includes the phrases "substantially straight", "substantially vertical" or "substantially tangent". For example, the phrase "straight wellbore section" or "substantially straight wellbore section" will mean to include any wellbore section that is "perfectly straight" or a section that has a relatively small curvature as described above and in more detail later.

<FIG> shows a drilling assembly <NUM> in a curved section of a wellbore <NUM>. In a non-limiting embodiment, the drilling assembly <NUM> includes a deflection device (also referred herein as a flexible device or a deflection mechanism) <NUM> for drilling curved and straight sections of the wellbore <NUM>. The drilling assembly <NUM> further includes a downhole drive or drive, such as a mud motor <NUM>, having a stator <NUM> and rotor <NUM>. The rotor <NUM> is coupled to a transmission, such as a flexible shaft <NUM> that is coupled to another shaft <NUM> (also referred to as the "drive shaft") disposed in a bearing assembly <NUM>. The shaft <NUM> is coupled to a disintegrating device, such as drill bit <NUM>. The drill bit <NUM> rotates when the drilling assembly <NUM> and/or the rotor <NUM> of the mud motor <NUM> rotates due to circulation of a drilling fluid, such as mud, during drilling operations. In other embodiments, the downhole drive may include any other device that can rotate the drill bit <NUM>, including, but not limited to an electric motor and a turbine. In certain other embodiments, the disintegrating device may include any another device suitable for disintegrating the rock formation, including, but not limited to, an electric impulse device (also referred to as electrical discharge device). The drilling assembly <NUM> is connected to a drill pipe <NUM>, which is rotated from the surface to rotate the drilling assembly <NUM> and thus the drilling assembly <NUM> and the drill bit <NUM>. In the particular drilling assembly configuration shown in <FIG>, the drill bit <NUM> may be rotated by rotating the drill pipe <NUM> and thus the drilling assembly <NUM> and/or the mud motor <NUM>. The rotor <NUM> rotates the drill bit <NUM> when a fluid is circulated through the drilling assembly <NUM>. The drilling assembly <NUM> further includes a deflection device <NUM> having an axis 120a that may be perpendicular to an axis 100a of the upper section of the drilling assembly <NUM>. In <FIG> the deflection device <NUM> is shown below the mud motor <NUM> and coupled to a lower section, such as housing or tubular <NUM> disposed over the bearing assembly <NUM>. In various embodiments of the deflection device <NUM> disclosed herein, the housing <NUM> tilts a selected or known amount along a selected or known plane defined by the axis of the upper section of the drilling assembly 110a and the axis of the lower section of the drilling assembly 100b in <FIG>) to tilt the drill bit <NUM> along the selected plane, which allows drilling of curved borehole sections. As described later in reference to <FIG>, the tilt is initiated when the drilling assembly <NUM> is stationary (not rotating) or substantially rotationally stationary. The curved section is then drilled by rotating the drill bit <NUM> by the mud motor <NUM> without rotating the drilling assembly <NUM>. The deflection device <NUM> straightens when the drilling assembly is rotated, which allows drilling of straight wellbore sections. Thus, in aspects, the deflection device <NUM> allows a selected tilt in the drilling assembly <NUM> that enables drilling of curved sections along desired wellbore paths when the drill pipe <NUM> and thus the drilling assembly <NUM> is rotationally stationary or substantially rotationally stationary and the drill bit <NUM> is rotated by the drive <NUM>. However, when the drilling assembly <NUM> is rotated, such as by rotating the drill pipe <NUM> from the surface, the tilt straightens and allows drilling of straight borehole sections, as described in more detail in reference to <FIG>. In one embodiment, a stabilizer <NUM> is provided below the deflection device <NUM> (between the deflection device <NUM> and the drill bit <NUM>) that initiates a bending moment in the deflection device <NUM> and also maintains the tilt when the drilling assembly <NUM> is not rotated and a weight on the drill bit is applied during drilling of the curved borehole sections. In another embodiment a stabilizer <NUM> may be provided above the deflection device <NUM> in addition to or without the stabilizer <NUM> to initiate the bending moment in the deflection device <NUM> and to maintain the tilt during drilling of curved wellbore sections. In other embodiments, more than one stabilizer may be provided above and/or below the deflection device <NUM>. Modeling may be performed to determine the location and number of stabilizers for optimum operation. In other embodiments, an additional bend may be provided at a suitable location above the deflection device <NUM>, which may include, but not limited to, a fixed bend, a flexible bend a deflection device and a pin or hinge device.

<FIG> shows a non-limiting embodiment of a deflection device <NUM> for use in a drilling assembly, such as the drilling assembly <NUM> shown in <FIG>. Referring to <FIG> and <FIG>, in one non-limiting embodiment, the deflection device <NUM> includes a pivot member, such as a pin or hinge <NUM> having an axis <NUM> that may be perpendicular to the longitudinal axis <NUM> of the drilling assembly <NUM>, about which the housing <NUM> of a lower section <NUM> of the drilling assembly <NUM> tilts or inclines a selected amount relatively to the upper section (part of an upper section) about the plane defined by the axis <NUM>. The housing <NUM> tilts between a substantially straight end stop <NUM> and an inclined end stop <NUM> that defines the maximum tilt. When the housing <NUM> of the lower section <NUM> is tilted in the opposite direction, the straight end stop <NUM> defines the straight position of the drilling assembly <NUM>, where the tilt is zero or alternatively a substantially straight position when the tilt is relatively small but greater than zero, such as about <NUM> degrees or greater. Such a tilt can aid in initiating the tilt of the lower section <NUM> of the drilling assembly <NUM> for drilling curved sections when the drilling assembly is rotationally stationary. In such embodiments, the housing <NUM> tilts along a particular plane or radial direction as defined by the pin axis <NUM>. One or more seals, such as seal <NUM>, provided between the inside of the housing <NUM> and another member of the drilling assembly <NUM> seals the inside section of the housing <NUM> below the seal <NUM> from the outside environment, such as the drilling fluid.

Still referring to <FIG> and <FIG>, when a weight on the bit <NUM> is applied and drilling progresses while the drill pipe <NUM> is substantially rotationally stationary, it will initiate a tilt of the housing <NUM> about the pin axis <NUM> of the pin <NUM>. The drill bit <NUM> and/or the stabilizer <NUM> below the deflection device <NUM> initiates a bending moment in the deflection device <NUM> and also maintains the tilt when the drill pipe <NUM> and thus the drilling assembly <NUM> is substantially rotationally stationary and a weight on the drill bit <NUM> is applied during drilling of the curved wellbore sections. Similarly, stabilizer <NUM>, in addition to or without the stabilizer <NUM> and the drill bit, may also determine the bending moment in the deflection device <NUM> and maintains the tilt during drilling of curved wellbore sections. Stabilizers <NUM> and <NUM> may be rotating or non-rotating devices. In one non-limiting embodiment, a dampening device or dampener <NUM> may be provided to reduce or control the rate of the tilt variation when the drilling assembly <NUM> is rotated. In one non-limiting embodiment, the dampener <NUM> may include a piston <NUM> and a compensator <NUM> in fluid communication with the piston <NUM> via a line 260a to reduce, restrict or control the rate of the tilt variation. Applying a force F1 on the housing <NUM> will cause the housing <NUM> and thus the lower section <NUM> to tilt about the pin axis <NUM>. Applying a force F1' opposite to the direction of force F1 on the housing <NUM> causes the housing <NUM> and thus the drilling assembly <NUM> to straighten or to tilt into the opposite direction of force F1'. The dampener may also be used to stabilize the straightened position of the housing <NUM> during rotation of the drilling assembly <NUM> from the surface. The operation of the dampening device <NUM> is described in more detail in reference to <FIG>. Any other suitable device, however, may be utilized to reduce or control the rate of the tilt variation of the drilling assembly <NUM> about the pin <NUM>.

Referring now to <FIG>, when the drill pipe <NUM> is substantially rotationally stationary (not rotating) and a weight is applied on the drill bit <NUM> while the drilling is progressing, the deflection device will initiate a tilt of the drilling assembly <NUM> at the pivot <NUM> about the pivot axis <NUM>. The rotating of the drill bit <NUM> by the downhole drive <NUM> will cause the drill bit <NUM> to initiate drilling of a curved section. As the drilling continues, the continuous weight applied on the drill bit <NUM> will continue to increase the tilt until the tilt reaches the maximum value defined by the inclined end stop <NUM>. Thus, in one aspect, a curved section may be drilled by including the pivot <NUM> in the drilling assembly <NUM> with a tilt defined by the inclined end stop <NUM>. If the dampening device <NUM> is included in the drilling assembly <NUM> as shown in <FIG>, tilting the drilling assembly <NUM> about the pivot <NUM> will cause the housing <NUM> in section <NUM> to apply a force F1 on the piston <NUM>, causing a fluid <NUM>, such as oil, to transfer from the piston <NUM> to the compensator <NUM> via a conduit or path, such as line 260a. The flow of the fluid <NUM> from the piston <NUM> to the compensator <NUM> may be restricted to reduce or control the rate of the tilt variation and avoid sudden tilting of the lower section <NUM>, as described in more detail in reference to <FIG>. In the particular illustrations of <FIG> and <FIG>, the drill bit <NUM> will drill a curved section upward. To drill a straight section after drilling the curved section, the drilling assembly <NUM> may be rotated <NUM> degrees to remove the tilt and then later rotated from the surface to drill the straight section. However, when the drilling assembly <NUM> is rotated, based on the positions of the stabilizers <NUM> and/or <NUM> or other wellbore equipment between the deflection device <NUM> and the drill bit <NUM> and in contact with the wellbore wall , bending forces in the wellbore act on the housing <NUM> and exert forces in opposite direction to the direction of force F1, thereby straightening the housing <NUM> and thus the drilling assembly <NUM>, which allows the fluid <NUM> to flow from the compensator <NUM> to the piston <NUM> causing the piston to move outwards. Such fluid flow may or may not be restricted, which allows the housing <NUM> and thus the lower section <NUM> to straighten rapidly (without substantial delay). The outward movement of the piston <NUM> may be supported by a spring, positioned in force communication with the piston <NUM>, the compensator <NUM>, or both. The straight end stops <NUM> restricts the movement of the member <NUM>, causing the lower section <NUM> to remain straight as long as the drilling assembly <NUM> is being rotated. Thus, the embodiment of the drilling assembly <NUM> shown in <FIG> and <FIG> provides a self-initiating tilt when the drilling assembly <NUM> is stationary (not rotated) or substantially stationary and straightens itself when the drilling assembly <NUM> is rotated. Although the downhole drive <NUM> shown in <FIG> is shown to be a mud motor, any other suitable drive may be utilized to rotate the drill bit <NUM>. <FIG> shows the drilling assembly <NUM> in the straight position, wherein the housing <NUM> rests against the straight end stop <NUM>.

<FIG> shows another non-limiting embodiment of a deflection device <NUM> that includes a force application device, such as a spring <NUM>, that continually exerts a radially outward force F2 on the housing <NUM> of the lower section <NUM> to provide or initiate a tilt to the lower section <NUM>. In one embodiment, the spring <NUM> may be placed between the inside of the housing <NUM> and a housing <NUM> outside the transmission <NUM> (<FIG>). In this embodiment, the spring <NUM> causes the housing <NUM> to tilt radially outward about the pivot <NUM> up to the maximum bend defined by the inclined end stop <NUM>. When the drilling assembly <NUM> is stationary (not rotating) or substantially rotationally stationary, a weight on the drill bit <NUM> is applied and the drill bit is rotated by the downhole drive <NUM>, the drill bit <NUM> will initiate the drilling of a curved section. As drilling continues, the tilt increases to its maximum level defined by the inclined end stop <NUM>. To drill a straight section, the drilling assembly <NUM> is rotated from the surface, which causes the borehole to apply force F3 on the housing <NUM>, compressing the spring <NUM> to straighten the drilling assembly <NUM>. When the spring <NUM> is compressed by application of force F3, the housing <NUM> relieves pressure on the piston <NUM>, which allows the fluid <NUM> from the compensator <NUM> to flow through line <NUM> back to piston <NUM> without substantial delay as described in more detail in reference to <FIG>.

<FIG> shows a non-limiting embodiment of a hydraulic force application device <NUM> to initiate a selected tilt in the drilling assembly <NUM>. In one non-limiting embodiment, the hydraulic force application device <NUM> includes a piston <NUM> and a compensation device or compensator <NUM>. The drilling assembly <NUM> also may include a dampening device or dampener, such as dampener <NUM> shown in <FIG>. The dampening device <NUM> includes a piston <NUM> and a compensator <NUM> shown and described in reference to <FIG>. The hydraulic force application device <NUM> may be placed <NUM> degrees from device <NUM>. The piston <NUM> and compensator <NUM> are in hydraulic communication with each other. During drilling, a fluid 512a, such as drilling mud, flows under pressure through the drilling assembly <NUM> and returns to the surface via an annulus between the drilling assembly <NUM> and the wellbore as shown by fluid 512b. The pressure P1 of the fluid 512a in the drilling assembly <NUM> is greater (typically <NUM>-<NUM> bars) than the pressure P2 of the fluid 512b in the annulus. When fluid 512a flows through the drilling assembly <NUM>, pressure P1 acts on the compensator <NUM> and correspondingly on the piston <NUM> while pressure P2 acts on compensator <NUM> and correspondingly on piston <NUM>. Pressure P1 being greater than pressure P2 creates a differential pressure (P1 - P2) across the piston <NUM>, which pressure differential is sufficient to cause the piston <NUM> to move radially outward, which pushes the housing <NUM> outward to initiate a tilt. A restrictor <NUM> may be provided in the compensator <NUM> to reduce or control the rate of the tilt variation as described in more detail in reference to <FIG>. Thus, when the drill pipe <NUM> is substantially rotationally stationary (not rotating), the piston <NUM> slowly bleeds the hydraulic fluid <NUM> through the restrictor <NUM> until the full tilt angle is achieved. The restrictor <NUM> may be selected to create a high flow resistance to prevent rapid piston movement which may be present during tool face fluctuations of the drilling assembly to stabilize the tilt. The differential pressure piston force is always present during circulation of the mud and the restrictor <NUM> limits the rate of the tilt. When the drilling assembly <NUM> is rotated, bending moments on the housing <NUM> force the piston <NUM> to retract, which straightens the drilling assembly <NUM> and then maintains it straight as long as the drilling assembly <NUM> is rotated. The dampening rate of the dampening device <NUM> may be set to a higher value than the rate of the device <NUM> in order to stabilize the straightened position during rotation of the drilling assembly <NUM>.

<FIG> show certain details of the dampening device <NUM>, which is the same as device <NUM> in <FIG>, <FIG>. Referring to <FIG> and <FIG> and 6B, when the housing <NUM> applies force F1 on the piston <NUM>, it moves a hydraulic fluid (such as oil) from a chamber <NUM> associated with the piston <NUM> to a chamber <NUM> associated with a compensator <NUM>, as shown by arrow <NUM>. A restrictor <NUM> restricts the flow of the fluid from the chamber <NUM> to chamber <NUM>, which increases the pressure between the piston <NUM> and the restrictor <NUM>, thereby restricting or controlling the rate of the tilt. As the hydraulic fluid flow continues through the restrictor <NUM>, the tilt continues to increase to the maximum level defined by the end inclination stop <NUM> shown and described in reference to <FIG>. Thus, the restrictor <NUM> defines the rate of the tilt variation. Referring to <FIG>, when force F1 is released from the housing <NUM>, as shown by arrow F4, force F5 on compensator <NUM> moves the fluid from chamber <NUM> back to the chamber <NUM> of piston <NUM> via a check valve <NUM>, bypassing the restrictor <NUM>, which enables the housing <NUM> to move to its straight position without substantial delay. A pressure relief valve <NUM> may be provided as a safety feature to avoid excessive pressure beyond the design specification of hydraulic elements.

<FIG> shows an alternative embodiment of a deflection device <NUM> that may be utilized in a drilling assembly, such as drilling assembly <NUM> shown in <FIG>. The deflection device <NUM> incudes a pin <NUM> with a pin axis <NUM> perpendicular to the tool axis <NUM>. The pin <NUM> is supported by a support member <NUM>. The deflection device <NUM> is connected to a lower section <NUM> of a drilling assembly and includes a housing <NUM>. The housing <NUM> includes an inner curved or spherical surface <NUM> that moves over an outer mating curved or spherical surface <NUM> of the support member <NUM>. The deflection device <NUM> further includes a seal <NUM> mechanism to separate or isolate a lubricating fluid (internal fluid) <NUM> from the external pressure and fluids (fluid 722a inside the drilling assembly and fluid 722b outside the drilling assembly). In one embodiment, the deflection device <NUM> includes a groove or chamber <NUM> that is open to and communicates the pressure of fluid 722a or 722b to a lubricating fluid <NUM> via a movable seal to an internal fluid chamber <NUM> that is in fluid communication with the surfaces <NUM> and <NUM>. A floating seal <NUM> provides pressure compensation to the chamber <NUM>. A seal <NUM> placed in a groove <NUM> around the inner surface <NUM> of the housing <NUM> seals or isolates the fluid <NUM> from the outside environment. Alternatively, the seal member <NUM> may be placed inside a groove around the outer surface <NUM> of the support member <NUM>. In these configurations, the center 770c of the surface <NUM> is same or about the same as the center 710c of the pin <NUM>. In the embodiment of <FIG>, when the lower section <NUM> tilts about the pin <NUM>, the surface <NUM> along with the seal member <NUM> moves over the surface <NUM>. If the seal <NUM> is disposed inside the surface <NUM>, then the seal member <NUM> will remain stationary along with the support member <NUM>. The seal mechanism <NUM> further includes a seal that isolates the lubrication fluid <NUM> from the external pressure and external fluid 722b. In the embodiment shown in <FIG>, this seal includes an outer curved or circular surface <NUM> associated with the lower section <NUM> that moves under a fixed mating curved or circular surface <NUM> of the upper section <NUM>. A seal member, such as an O-ring <NUM>, placed in a groove <NUM> around the inside of the surface <NUM> seals the lubricating fluid <NUM> from the outside pressure and fluid 722b. When the lower section tilts about the pin <NUM>, the surface <NUM> moves under the surface <NUM>, wherein the seal <NUM> remains stationary. Alternatively, the seal <NUM> may be placed inside the outer surface <NUM> and in that case, such a seal will move along with the surface <NUM>. Thus, in aspects, the disclosure provides a sealed deflection device, wherein the lower section of a drilling assembly, such as section <NUM>, tilts about sealed lubricated surfaces relative to the upper section, such as section <NUM>. In one embodiment, the lower section <NUM> may be configured that enables the lower section <NUM> to attain perfectly straight position relative to the upper section <NUM>. In such a configuration, the tool axis <NUM> and the axis <NUM> of the lower section <NUM> will align with each other. In another embodiment, the lower section <NUM> may be configured to provide a permanent minimum tilt of the lower section <NUM> relative to the upper section, such as tilt Amin shown in <FIG>. Such a tilt can aid the lower section to tilt from the initial position of tilt Amin to a desired tilt compared to a no initial tilt of the lower section. As an example, the minimum tilt may be <NUM> degree or greater may be sufficient for a majority of drilling operations.

<FIG> shows the deflection device <NUM> of <FIG> when the lower section <NUM> has attained a full or maximum tilt or tilt angle Amax. In one embodiment, when the lower section <NUM> continues to tilt about the pin <NUM>, a surface <NUM> of the lower section <NUM> is stopped by a surface <NUM> of the upper section <NUM>. The gap <NUM> between the surfaces <NUM> and <NUM> defines the maximum tilt angle Amax. A port <NUM> is provided to fill the chamber <NUM> with the lubrication fluid <NUM>. In one embodiment a pressure communication port <NUM> is provided for to allow pressure communication of fluid 722b outside the drilling assembly with the chamber <NUM> and the pressure of the internal fluid chamber <NUM> via the floating seal <NUM>. In <FIG>, shoulder <NUM> acts as the tilt end stop. The internal fluid chamber <NUM> may also be used as a dampening device. The dampener device uses fluid present at the gap <NUM> as displayed in <FIG> in a maximum tilt position defined by the maximum tilt angle Amax being forced or squeezed from the gap <NUM> when the tilt is reduced towards Amin. Suitable fluid passages are designed to enable and restrict flow between both sides of the gap <NUM> and other areas of the fluid chamber <NUM> that exchange fluid volume by movement of the deflection device. To support the dampening, suitable seals, gap dimensions or labyrinth seals may be added. The lubricating fluid <NUM> properties in terms of density and viscosity can be selected to adjust the dampening parameters.

<FIG> is a <NUM> degree rotated view of the deflection device <NUM> of <FIG> showing a sealed hydraulic section <NUM> of the deflection device <NUM>. In one non-limiting embodiment, the sealed hydraulic section <NUM> includes a reservoir or chamber <NUM> filled with a lubricant <NUM> that is in fluid communication with each of the seals in the deflection device <NUM> via certain fluid flow paths. In <FIG>, a fluid path 932a provides lubricant <NUM> to the outer seal <NUM>, fluid path 932b provides lubricant <NUM> to a stationary seal <NUM> around the pin <NUM> and a fluid flow path 932c provides lubricant <NUM> to the inner seal <NUM>. In the configuration of <FIG>, seal <NUM> isolates the lubricant from contamination from the drilling fluid 722a flowing through the drilling assembly and from pressure P1 of the drilling fluid 722a inside the drilling assembly that is higher than pressure P2 on the outside of the drilling assembly during drilling operations. Seal <NUM> isolates the lubricant <NUM> from contamination by the outer fluid 722b. In one embodiment seal <NUM> may be a bellows seal. The flexible bellows seal may be used as a pressure compensation device (instead of using a dedicated device, such as a floating seal <NUM> as described in reference to <FIG>) to communicate the pressure from fluid 722b to the lubricant <NUM>. Seal <NUM> isolates the lubricant <NUM> from contamination by the outer fluid 722b and around the Pin <NUM>. Seal <NUM> allows differential movement between the pin <NUM> and the lower section member <NUM>. Seal <NUM> is also in fluid communication with the lubricant <NUM> through fluid flow path 932c. Since the pressure between fluid 722b and the lubricant <NUM> is equalized through seal <NUM>, the pin seal <NUM> does not isolate two pressure levels, enabling longer service life for a dynamic seal function, such as for seal <NUM>.

<FIG> shows the deflection device <NUM> of <FIG> that may be configured to include one or more flexible seals to isolate the dynamic seals <NUM> and <NUM> from the drilling fluid. A flexible seal is any seal that expands and contracts as the lubricant volume inside such a seal respectively increases and decreases and one that allows for the movement between parts that are desired to be sealed. Any suitable flexible may be utilized, including, but not limited to, a bellow seal, and a flexible rubber seal. In the configuration of <FIG>, a flexible seal <NUM> is provided around the dynamic seal <NUM> that isolates the seal <NUM> from fluid 722b on the outside of the drilling assembly. A flexible seal <NUM> is provided around the dynamic seal <NUM> that protects the seal <NUM> from the fluid 722a inside the drilling assembly. A deflection device made according to the disclosure herein may be configured: ; a single seal, such as seal <NUM>, that isolates the fluid flowing through the drilling assembly inside and its pressure from the fluid on the outside of the drilling assembly; a second seal, such as seal <NUM>, that isolates the outside fluid from the inside fluid or components of the deflection device <NUM>; one or more flexible seals to isolate one or more other seals, such as the dynamic seals <NUM> and <NUM>; and a lubricant reservoir, such as reservoir <NUM> (<FIG>) enclosed by at least two seals to lubricate the various seals of the deflection device <NUM>.

<FIG> shows the deflection device of <FIG> that includes a locking device to prevent the pin or hinge member <NUM> of the deflection device from rotating. In the configuration of <FIG>, a locking member <NUM> may be placed between the pin <NUM> and a member or element of the non-moving member <NUM> of the drilling assembly. The locking member <NUM> may be a keyed element or member, such as a pin, that prevents rotation of the pin <NUM> when the lower section <NUM> tilts or rotates about the pin <NUM>. Any other suitable device or mechanism also may be utilized as the locking device, including, but not limited to, a friction and adhesion devices.

<FIG> shows the deflection device <NUM> of <FIG> that includes a friction reduction device <NUM> between the pin or hinge member <NUM> of the deflection device <NUM> and a member or surface <NUM> of the lower section <NUM> that moves about the pin <NUM>. The friction reduction device <NUM> may be any device that reduces friction between moving members, including, but not limited to bearings.

<FIG> shows the deflection device <NUM> of <FIG> that in one aspect includes a sensor <NUM> that provides measurements relating to the tilt or tilt angle of the lower section <NUM> relative to the upper section <NUM>. In one non-limiting embodiment, sensor <NUM> (also referred herein as the tilt sensor) may be placed along, about or at least partially embedded in the pin <NUM>. Any suitable sensor may be used as sensor <NUM> to determine the tilt or tilt angle, including, but not limited to, an angular sensor, a hall-effect sensor, a magnetic sensor, and contact or tactile sensor. Such sensors may also be used to determine the rate of the tilt variation. If such a sensor includes two components that face each other or move relative to each other, then one such component may be placed on, along or embedded in an outer surface 710a of the pin <NUM> and the other component may be placed on, along or embedded on an inside 790a of the lower section <NUM> that moves or rotates about the pin <NUM>. In another aspect, a distance sensor <NUM> may be placed, for example, in the gap <NUM> that provides measurements about the distance or length of the gap <NUM>. The gap length measurement may be used to determine the tilt or the tilt angle or the rate of the tilt variation. Additionally, one or more sensors <NUM> may be placed in the gap <NUM> to provide signal relating to the presence of contact between and the amount of the force applied by the lower section <NUM> on the upper section <NUM>.

<FIG> shows the deflection device <NUM> of <FIG> that includes sensors <NUM> in a section <NUM> of the upper section <NUM> that provide information about the drilling assembly parameters and the wellbore parameters that are useful for drilling the wellbore along a desired well path, sometimes referred to in the art as "geosteering". Some such sensors may include sensors that provide measurements relating to parameters such as tool face, inclination (gravity), and direction (magnetic). Accelerometers, magnetometers, and gyroscopes may be utilized for such parameters. In addition, a vibration sensor may be located at location <NUM>. In one non-limiting embodiment, section <NUM> may be in the upper section <NUM> proximate to the end stop <NUM>. Sensors <NUM>, however, may be located at any other suitable location in the drilling assembly above or below the deflection device <NUM> or in the drill bit. In addition, sensors <NUM> may be placed in the pin <NUM> for providing information about certain physical conditions of the deflection device <NUM>, including, but not limited to, torque, bending and weight. Such sensors may be placed in and/or around the pin <NUM> as relevant forces relating to such parameters are transferred through the pin <NUM>.

<FIG> shows the deflection device <NUM> of <FIG> that includes a device <NUM> for generating electrical energy due deflection dynamics, such as vibration, motion and strain energy in the defection device <NUM> and the drilling assembly. The device <NUM> may include, but is not limited to, piezoelectric crystals, electromagnetic generator, MEMS device. The generated energy may be stored in a storage device, such as battery or a capacitor <NUM>, in the drilling assembly and may be utilized to power various sensors, electrical circuits and other devices in the drilling assembly.

Referring to <FIG>, signals from sensors <NUM>, <NUM>, <NUM>, <NUM>, and <NUM> may be transmitted or communicated to a controller or another suitable circuit in the drilling assembly by hard wire, optical device or wireless transmission method, including, but limited to, acoustic, radio frequency and electromagnetic methods. The controller in the drilling assembly may process the sensor signals, store such information a memory in the drilling assembly and/or communicate or transmit in real time relevant information to a surface controller via any suitable telemetry method, including, but not limited to, wired pipe, mud pulse telemetry, acoustic transmission, and electromagnetic telemetry. The tilt information from sensor <NUM> may be utilized by an operator to control drilling direction along a desired or predetermined well path, i.e. geosteering and to control operating parameters, such as weight on bit. Information about the force applied by the lower section <NUM> onto the upper section <NUM> by sensor <NUM> may be used to control the weight on the drill bit to mitigate damage to the deflection device <NUM>. Torque, bending and weight information from sensors <NUM> is relevant to the health of the deflection device and the drilling process and may be utilized to control drilling parameter, such as applied and transferred weight on the drill bit. Information about the pressure inside the drilling assembly and in the annuls may be utilized to control the differential pressure around the seals and thus on the lubricant.

<FIG> is a schematic diagram of an exemplary drilling system <NUM> that may utilize a drilling assembly <NUM> that includes a deflection device <NUM> described in reference to <FIG> for drilling straight and deviated wellbores. The drilling system <NUM> is shown to include a wellbore <NUM> being formed in a formation <NUM> that includes an upper wellbore section <NUM> with a casing <NUM> installed therein and a lower wellbore section <NUM> being drilled with a drill string <NUM>. The drill string <NUM> includes a tubular member <NUM> that carries a drilling assembly <NUM> at its bottom end. The tubular member <NUM> may be a drill pipe made up by joining pipe sections, a coiled tubing string, or a combination thereof. The drilling assembly <NUM> is shown connected to a disintegrating device, such as a drill bit <NUM>, attached to its bottom end. The drilling assembly <NUM> includes a number of devices, tools and sensors for providing information relating to various parameters of the formation <NUM>, drilling assembly <NUM> and the drilling operations. The drilling assembly <NUM> includes a deflection device <NUM> made according to an embodiment described in reference to <FIG><NUM>. In <FIG>, the drill string <NUM> is shown conveyed into the wellbore <NUM> from an exemplary rig <NUM> at the surface <NUM>. The exemplary rig <NUM> is shown as a land rig for ease of explanation. The apparatus and methods disclosed herein may also be utilized with offshore rigs. A rotary table <NUM> or a top drive 1669a coupled to the drill string <NUM> may be utilized to rotate the drill string <NUM> and thus the drilling assembly <NUM>. A control unit <NUM> (also referred to as a "controller" or a "surface controller"), which may be a computer-based system, at the surface <NUM> may be utilized for receiving and processing data received from sensors in the drilling assembly <NUM> and for controlling s drilling operations of the various devices and sensors in the drilling assembly <NUM>. The surface controller <NUM> may include a processor <NUM>, a data storage device (or a computer-readable medium) <NUM> for storing data and computer programs <NUM> accessible to the processor <NUM> for determining various parameters of interest during drilling of the wellbore <NUM> and for controlling selected operations of the various devices and tools in the drilling assembly <NUM> and those for drilling of the wellbore <NUM>. The data storage device <NUM> may be any suitable device, including, but not limited to, a read-only memory (ROM), a random-access memory (RAM), a flash memory, a magnetic tape, a hard disc and an optical disk. To drill wellbore <NUM>, a drilling fluid <NUM> is pumped under pressure into the tubular member <NUM>, which fluid passes through the drilling assembly <NUM> and discharges at the bottom 1610a of the drill bit <NUM>. The drill bit <NUM> disintegrates the formation rock into cuttings <NUM>. The drilling fluid <NUM> returns to the surface <NUM> along with the cuttings <NUM> via the annular space (also referred as the "annulus") <NUM> between the drill string <NUM> and the wellbore <NUM>.

Still referring to <FIG>, the drilling assembly <NUM> may further include one or more downhole sensors (also referred to as the measurement-while-drilling (MWD) sensors, logging-while-drilling (LWD) sensors or tools, and sensors described in reference to <FIG>, collectively referred to as downhole devices and designated by numeral <NUM>, and at least one control unit or controller <NUM> for processing data received from the downhole devices <NUM>. The downhole devices <NUM> include a variety of sensors that provide measurements or information relating to the direction, position, and/or orientation of the drilling assembly <NUM> and/or the drill bit <NUM> in real time. Such sensors include, but are not limited to, accelerometers, magnetometers, gyroscopes, depth measurement sensors, rate of penetration measurement devices. Devices <NUM> also include sensors that provide information about the drill string behavior and the drilling operations, including, but not limited to, sensors that provide information about vibration, whirl, stick-slip, rate of penetration of the drill bit into the formation, weight-on-bit, torque, bending, whirl, flow rate, temperature and pressure. The devices <NUM> further may include tools or devices that provide measurement or information about properties of rocks, gas, fluids, or any combination thereof in the formation <NUM>, including, but not limited to, a resistivity tool, an acoustic tool, a gamma ray tool, a nuclear tool, a sampling or testing tool, a coring tool, and a nuclear magnetic resonance tool. The drilling assembly <NUM> also includes a power generation device <NUM> for providing electrical energy to the various downhole devices <NUM> and a telemetry system or unit <NUM>, which may utilize any suitable telemetry technique, including, but not limited to, mud pulse telemetry, electromagnetic telemetry, acoustic telemetry and wired pipe. Such telemetry techniques are known in the art and are thus not described herein in detail. Drilling assembly <NUM>, as mentioned above, further includes a deflection device (also referred to as a steering unit or device) <NUM> that enables an operator to steer the drill bit <NUM> in desired directions to drill deviated wellbores. Stabilizers, such as stabilizers <NUM> and <NUM> are provided along the steering section <NUM> to stabilize the section containing the deflection device <NUM> (also referred to as the steering section) and the rest of the drilling assembly <NUM>. The downhole controller <NUM> may include a processor <NUM>, such as a microprocessor, a data storage device <NUM> and a program <NUM> accessible to the processor <NUM>. In aspects, the controller <NUM> receives measurements from the various sensors during drilling and may partially or completely process such signals to determine one or more parameters of interest and cause the telemetry system <NUM> to transmit some or all such information to the surface controller <NUM>. In aspects, the controller <NUM> may determine the location and orientation of the drilling assembly or the drill bit and send such information to the surface. Alternatively, or in addition thereto, the controller <NUM> at the surface determines such parameters from data received from the drilling assembly. An operator at the surface, controller <NUM> and/or controller <NUM> may orient (direction and tilt) the drilling assembly along desired directions to drill deviated wellbore sections in response to such determined or computed directional parameters. The drilling system <NUM>, in various aspects, allows an operator to orient the defection device in any desired direction by orienting the drilling assembly based on orientation measurement (for instance relative to north, relative to high side, etc.) that are determined at the surface from downhole measurements described earlier to drill curved and straight sections along desired well paths, monitor drilling direction, and continually adjust orientation as desired in response to the various parameters sensor determined from the sensors described herein and to adjust the drilling parameters to mitigate damage to the components of the drilling assembly. Such actions and adjustments may be done automatically by the controllers in the system or by input from an operator or semi-manually.

Thus, in certain aspects, the deflection device includes one or more sensors that provide measurements relating to directional drilling parameters or the status of the deflection device, such as an angle or angle rate, a distance or distance rate, both relating to the tilt or tilt rate. Such a sensor may include, but not limied to, a bending sensor and an electromagnetic sensor. The electromagnetic sensor translates the angle change or the distance change that is related to the tilt change into a voltage using the induction law or a capacity change. Either the same sensor or another sensor may measure drilling dynamic parameters, such as acceleration, weight on bit, bending, torque, RPM. The deflection device may also include formation evaluation sensors that are used to make geosteering decisions, either via communication to the surface or automatically via a downhole controller. Formation evaluation sensors, such as resistivity, acoustic, nuclear magnetic resonance (NMR), nuclear, etc. may be used to identify downhole formation features, including geological boundaries.

In certain other aspects, the drilling assemblies described herein include a deflection device that: (<NUM>) provides a tilt when the drilling assembly is not rotated and the drill bit is rotated by a downhole drive, such as a mud motor, to allow drilling of curved or articulated borehole sections; and (<NUM>) the tilt straightens when the drilling assembly is rotated to allow drilling of straight borehole sections. In one non-limiting embodiment, a mechanical force application device may be provided to initiate the tilt. In another non-limiting embodiment, a hydraulic device may be provided to initiate the tilt. A dampening device may be provided to aid in maintaining the tilt straight when the drilling assembly is rotated. A dampening device may also be provided to support the articulated position of the drilling assembly when rapid forces are exerted onto the tilt such as during tool face fluctuations. Additionally, a restrictor may be provided to reduce or control the rate of the tilt. Thus, in various aspects, the drilling assembly automatically articulates into a tilted or hinged position when the drilling assembly is not rotated and automatically attains a straight or substantially straight position when the drilling assembly is rotated. Sensors provide information about the direction (position and orientation) of the lower drilling assembly in the wellbore, which information is used to orient the lower section of the drilling assembly along a desired drilling direction. A permanent predetermined tilt may be provided to aid the tilting of the lower section when the drilling assembly is rotationally stationary. End stops are provided in the deflection device that define the minimum and maximum tilt of the lower section relative to the upper section of the drilling assembly. A variety of sensors in the drilling assembly, including those in or associated with the deflection device, are used to drill wellbores along desired well paths and to take corrective actions to mitigate damage to the components of the drilling assembly. For the purpose of this disclosure, substantially rotationally stationary generally means the drilling assembly is not rotated by rotating the drill string from the surface. The phrase "substantially rotationally stationary" and the term "stationary" are considered equivalent. Also, a "straight" section is intended to include a "substantially straight" section.

Claim 1:
An apparatus comprising a drill pipe (<NUM>) and a drilling assembly (<NUM>) connected to the drill pipe (<NUM>) for drilling a wellbore, the drill pipe (<NUM>) configured to be rotated from the surface to rotate the drilling assembly (<NUM>), the drilling assembly (<NUM>) comprising:
an upper section (<NUM>), and a lower section (<NUM>; <NUM>) separate from the upper section (<NUM>);
a downhole drive (<NUM>) for rotating a drill bit (<NUM>) relative to the drill pipe (<NUM>);
a deflection device (<NUM>; <NUM>) comprising a housing and a pivot member (<NUM>; <NUM>) that couples the upper section (<NUM>) to the lower section (<NUM>; <NUM>) to allow the lower section (<NUM>; <NUM>) to tilt relative to the upper section (<NUM>) about an axis (<NUM>; <NUM>) of the pivot member (<NUM>; <NUM>) when the drill pipe (<NUM>) is substantially rotationally stationary to allow drilling of a curved section of the wellbore when the drill bit (<NUM>) is rotated by the downhole drive (<NUM>), and
wherein rotating the drill pipe (<NUM>) reduces the tilt between the upper section (<NUM>) and the lower section (<NUM>; <NUM>) to allow drilling of a straighter section of the wellbore; and
a tilt sensor (<NUM>) that provides measurements relating to tilt of the lower section (<NUM>; <NUM>),
characterized by:
the pivot member (<NUM>; <NUM>) comprising a first pin through a wall of the housing and a second pin through the wall of the housing.