TOOL FOR MEASURING WELLBORE GEOMETRY
A downhole tool is disclosed for measuring wellbore geometry. The downhole tool may include a body with a bore extending at least partially therethrough. The body may include a radial recess. An arm may be movably coupled to the body at a first end portion of the arm. The arm may be within the radial recess in a retracted position and be pivotable in a radially-outward direction relative to the body to an expanded position. A measurement device coupled to the body may measure the pivoting motion of the arm. A piston coupled to the body may be movably coupled to a second end portion of the arm, and the piston may respond to changes in hydraulic pressure to pivot the arm between the retracted position and the expanded position.
Latest SMITH INTERNATIONAL, INC. Patents:
Embodiments described herein generally relate to downhole tools. More particularly, embodiments of the present disclosure relate to downhole tools for measuring a diameter or other geometry of a wellbore while performing drilling or remedial operations within a wellbore.
BACKGROUND INFORMATIONWellbores drilled in subterranean formations, such as oilfields, often have irregular shapes. In particular, walls of the wellbore are not perfectly smooth, and the magnitude of such irregularities may be particularly great where the borehole traverses weak, highly stressed, or fractured rock. Wellbore shape and geometry can provide an indication of the mechanical stability of the wellbore, and knowing the wellbore shape and geometry can be useful in downhole operations such as drilling, reaming, producing, casing, and plugging.
The diameter of the wellbore is oftentimes measured by an ultrasonic measurement tool, which measures the diameter of the wellbore using acoustic pulses and echoes. On wireline tools with limited drilling or remedial tools, local diameter measurements may also be made with mechanical arms. By combining measurements at different angular orientations and depths, wellbore geometry may be mapped out in two-dimensional or three-dimensional space.
SUMMARYEmbodiments of the present disclosure may relate to a downhole tool for measuring wellbore geometry. An illustrative downhole tool may include a body with a bore extending fully or partially therethrough. An aperture may also extend radially through a portion of the body. An arm with opposing ends may have one end movably coupled to the body. The arm may pivot to move between retracted and expanded positions. In the retracted position, the arm may be within the aperture, and in the expanded position the arm may be at least partially radially outward relative to the body and aperture. A piston in the bore of the body may be coupled to the second end of the arm and may respond to hydraulic pressure to cause the arm to pivot and move between the retracted position and the expanded position.
In accordance with another embodiment, a tool for measuring geometry includes a body with a bore therein. A piston coupled to the body may move axially within the body when hydraulic pressure of fluid in the bore is increased. A spring gear assembly coupled to the piston may rotate when the piston moves between two positions. An arm coupled to the body and the spring gear assembly may move radially relative to the body upon rotation of the spring gear assembly, and a measuring device coupled to the arm may measure rotational or other movement of the arm.
An example embodiment for measuring a diameter of a wellbore while performing a downhole drilling or remedial operation may include increasing a pressure of a fluid within a bore of a body of a downhole tool in the wellbore. A piston may move axially in response to the increased pressure, and an arm movably coupled to the body may be pivoted radially-outward in response to axial movement of the piston. A measuring device coupled to the arm may sense the pivoting motion of the arm while drilling or while performing a remedial operation, and the pivotal movement of the arm may be used to determine a diameter of the wellbore.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
So that features of claimed and described embodiments may be understood in detail, a more particular description may be had by reference to one or more embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings represent illustrative embodiments, and are, therefore, not to be considered limiting of the scope of the present disclosure. Moreover, while the drawings generally illustrate certain embodiments at a scale useful for some applications, the drawings should not be interpreted as being to scale for each embodiment which may be described or claimed herein.
Some embodiments described herein generally relate to downhole tools. More particularly, some embodiments of the present disclosure relate to downhole tools for measuring a diameter or other geometry of a wellbore while performing drilling or remedial operations within the wellbore.
In accordance with some embodiments, the body 110 may have one or more openings, radial recesses, or apertures (three apertures 122 are shown in
In some embodiments, a caliper system 136 may be at least partially positioned within each aperture 122. In this particular embodiment, the caliper system 136 may include an arm assembly 140, a spring gear assembly 160, and a pin slot connector 180. The arm assembly 140 may include an arm 142 having a roller 144 coupled thereto. The pin slot connector 180 may be coupled to the arm 142 and the spring gear assembly 160 may be coupled to the pin slot connector 180. Although three (3) apertures 122 and caliper systems 136 are shown in
In the illustrated embodiment, a piston 150 may be disposed within the body 110 and configured to move axially within the body 110. The piston 150 may include a head 152 having a shaft 154 coupled thereto and extending axially therefrom. The head 152 may abut the lower cap 106, and the shaft 154 may extend axially toward the caliper system 136 and/or the upper end portion 114. In some embodiments, the shaft 154 may be coupled to the mandrel 156 (e.g., a lower end of the mandrel). In the particular embodiment shown in
In
Each spring gear assembly 160 may be coupled to the body 110 and/or to the shaft 154 of the piston 150. For example, each spring gear assembly 160 may be coupled to the body 110 via a support bar 188 as shown in
According to some embodiments, the shaft 154 of the piston 150 may be configured to move axially with respect to the spring gear assemblies 160 and the body 110. The spring gear assemblies 160 may each include a spring 162. The spring 162 may act as a biasing member to bias at least a portion of the spring gear assemblies 160. For instance, the spring 162 may be a torsion spring configured to rotate about the support bar 188 and/or to bias a portion of the spring gear assembly 160 towards rotation in a particular direction around the support bar 188.
Each spring gear assembly 160 may be coupled to a corresponding arm assembly 140. In some embodiments, the spring gear assemblies 160 are coupled to corresponding arm assemblies 140 via a pin slot connector 180. More particularly, a pin connector 170 of the pin slot connector 180 may be coupled to each spring gear assembly 160, and a slot connector 182 of the pin slot connector 180 may be coupled to each arm assembly 140. The pin connector 170 may include a pin 172 extending therefrom. The pin 172 may be positioned within a slot 184 formed in the corresponding slot connector 182. In some embodiments, the slot 184 may have an elongate shape. In such an embodiment, the pin 172 may be axially movable along the elongate length of the slot 184. Although not specifically shown, in another embodiment, the pin connectors 170 may be coupled to a corresponding arm assembly 140, and the slot connectors 182 may be coupled to a corresponding spring gear assembly 160.
The arm 142 of each arm assembly 140 may be coupled to a measurement device 124. In this embodiment, the measurement device 124 may be positioned around the mandrel 156, and in the annular region between the mandrel 156 and the body 110. The measurement device 124 may be configured to sense or measure movement of the arm 142. For example, the arm 142 may be pivotally connected to the measurement device 124. The measurement device 124 may sense or measure the rotational or pivoting movement of the arm 142 with a mechanical device, electronic device (e.g., an electromagnet and/or radio transmitter), a potential meter, a rotary encoder, or the like. As discussed in greater detail herein, in one embodiment, the measurement device 124 may include a magnet or other position indicator. Such a position indicator may move axially within the measurement device 124. In at least some embodiments, the distance that the position indicator moves axially may correspond to the rotational/pivoting movement of the arm 142 and/or the radial movement of the arm assembly 140.
The measurement device 124 may be in communication with a probe or other electronic device that is optionally disposed within the bore 112 of the mandrel 156. The electronic device 134 may include a magnetometer. For example, a magnetometer in the electronic device 134 may be configured to detect the position of the magnet in the measurement device 124, which position may correspond to the position of the arm 142. The electronic device 134 may also include a transmitter configured to transmit the measurement to another downhole tool (e.g., a measurement-while-drilling (MWD) tool, a logging-while-drilling (LWD), a mud-pulse telemetry transmitter, etc.) or to the surface. Such transmission may occur in real-time or near real-time. Real-time or near real-time transmission may allow monitoring/recording (e.g., at an uphole or surface location) of the diameter or other geometry of the wellbore 102 (
The spring gear assembly 160 may include a gear 168 that has a plurality of clogs or teeth 164 formed on the outer surface thereof. The teeth 164 on the gear 168 may be circumferentially offset from one another, with each configured to fit within or engage the teeth 166 on the shaft 154. In the illustrated embodiment, the teeth 164 may extend circumferentially around a portion of the gear 168. For instance, the teeth 164 may extend around between 90° and 270° of the gear 168; although, in other embodiments the teeth 164 may extend around less than 90° or greater than 270° of the gear 168. In more particular example embodiments, the teeth 164 may extend around between 130° and 150°, between 140° and 160°, between 150° and 170°, between 160° and 180°, between 170° and 190°, between 180° and 200°, or between 190° and 210°, between 200° and 220°, or between 210° and 230°. In some embodiments, the teeth 164 may extend around a full circumference of the gear 168.
The circumferentially offset of the teeth 164 may correspond to the axial distance between the teeth 166. Consequently, when the shaft 154 of the piston 150 moves axially with respect to the spring gear assembly 160 of the illustrated embodiment, the engagement of the teeth 164, 166 may cause the gear 168 to rotate and move axially along the rack of teeth 166. In such an arrangement, the gear 168 may operate as a pinion cooperating with the rack of teeth 166.
The support sleeve 186 may be positioned inside the spring 162 and/or the frame 178. In at least some embodiments, the support sleeve 186 may be used to center or otherwise maintain a desired positioning of the spring 162 within the frame 178 while the spring 162 winds and unwinds. In some embodiments, the frame 178 may include a second slot 174 configured to have a tab 176 of the pin connector 170 positioned therein. In the illustrated embodiment, the tab 176 and the slot 174 may have elongated shape. Optionally, such a shape may be used to limit if not prevent relative rotation between the pin connector 170 and the frame 178. In the same or other embodiments, the tab 176 may be sized to be about the same size as the slot 174 to further restrict or even prevent relative axial movement between the pin connector 170 and the frame 178. In other embodiments, however, the slot 174 and/or tab 176 may have other shapes or configurations. For instance, the tab 176 may have a circular shape to allow rotation within the slot 174. The slot 174 may also be circular or have another shape or configuration.
The arm 142 of the arm assembly 140 may be coupled to the gear shaft 126 such that the rotational movement of the arm 142 is transferred to the gear shaft 126. The gear shaft 126 may be coupled to the gear 128 such that the rotational movement of the gear shaft 126 may be transferred to the gear 128. Although a single gear 128 is shown in
The first and/or second gear 128-1, 128-2 may be coupled to a first pulley 130-1 by direct engagement or through indirect engagement of one or more other gears. In the illustrated embodiment, the rotational movement of the gear 128-2 may cause the first pulley 130-1 to rotate. More particularly, the gear shaft 126 may rotate. The gear 128-1 may be co-axial with the gear shaft 126 and may therefore rotate as the gear shaft 126 rotates. By virtue of engagement between the gear 128-2 and the gear 128-1, the gear 128-1 may also be caused to rotate. As shown in
When the first pulley 130-1 rotates, the rotation may cause a line or cable 123 disposed at least partially thereabout to move the magnet 132 in a linear or axial direction within the measurement device 124. The second pulley 130-2 may serve to reduce or prevent slack in the cable 123. In some embodiments, the cable 123 may be tensioned. For instance, the cable 123 may be tensioned by a preloaded torsion spring 125 or other biasing or tensioning member.
The movement of the magnet 132 may correspond to the rotational/pivoting movement of the arm 142 (see
A probe or other electronic device 134 (see
In some embodiments, a mandrel 356 may be shaped and sized to form one or more flow channels (three are shown 339-1, 339-2, 339-3) between the mandrel 356 and an electronic device 334 (see
An electronic device (e.g., 334 of
Each sensor 441-1, 441-2, 441-3 may sense the location and/or movement of a corresponding magnet 432-1, 432-2, 432-3 or other positioning device. Each magnet 432-1, 432-2, 432-3 may be configured to move linearly within a single one of the zones 443-1, 443-2, 443-3. In one embodiment, the zones 443-1, 443-2, 443-3 may be axially offset from one another so that the magnets 432-1, 432-2, 432-3 have reduced or even no “cross-talk” with one another. In some embodiments, the zones 443-1, 443-2, 443-3 may be axially offset to have no overlap. In other embodiments, one or more of the magnets 432-1, 432-2, 432-3 may be configured to move within multiple zones 443-1, 443-2, 443-3. As discussed herein, the position of a magnet 432-1, 432-2, 432-3 may be related to the position of an arm assembly used to measure or otherwise determine wellbore geometry.
In this particular embodiment, an arm assembly 540 may be folded or otherwise retracted into a body 510 of the downhole tool 500. When the downhole tool 500 is in the inactive state, a piston 550 may be positioned proximate a lower end portion 516 of the body 510. The spring 590 may also be generally uncompressed in such an embodiment. In addition, the arm 542 and the roller 544 (or other device for engaging a wall of a wellbore) may be folded or otherwise retracted into an aperture 522 of the body 510, and the outer surface of the arm 542 and/or a roller 544 may be aligned with, or positioned radially-inward from, the outer surface 518 of the body 510.
When the arm assembly 540 is obstructed, as shown in
More particularly,
The outer shoulder 657 of the mandrel 656 and/or the radial surface 611 of the body 610 may be straight, tapered, curved, or otherwise contoured. When the outer shoulder 657 is straight, it may be substantially perpendicular to a longitudinal axis extending through the mandrel 656 and/or the body 610. The straight outer shoulder 657 may not affect the centralization of the mandrel 656 because may not push the measuring devices 624 radially outward. Thus, there may not be a reaction force applied radially on the mandrel 656 to shift the mandrel 656 from its central location. When the outer shoulder 657 is tapered, the taper may be oriented at an angle between 2° and 130°. For instance, the angle may range from a low of 5°, 10°, 20°, or 30° to a high of 45°, 60°, 75°, or more with respect to the longitudinal axis extending through the mandrel 656 and/or body 610 (where 90° is perpendicular to the longitudinal axis). When the outer shoulder 657 is tapered, the outer shoulder 657 may apply a force to the measuring device 624 in the axial and radial directions, and this may tend to push the mandrel 656 off-center.
Once the downhole tool 600 is assembled, the downhole tool 600 may be run into a wellbore (e.g., wellbore 102 of
To actuate the downhole tool 600 into the active state, the hydrostatic pressure of the fluid in a bore (e.g., bore 112 of
As the piston moves toward the upper end portion 614 of the downhole tool 600, a shaft (e.g., shaft 154 of
More particularly, and as described in more detail with respect to the spring gear assembly 160 of
With continued reference to the illustrative embodiment shown in
The downhole tool 600 may rotate about a longitudinal axis extending therethrough, and the wellbore engagement elements may be configured to roll or slide along the wall of the wellbore. In at least one embodiment, one or more of the wellbore engagement elements may not expand radially-outward (or may expand radially-outward a lesser amount relative to other wellbore engagement elements) because the wall of the wellbore may be contacting or near the outer surface of the body 610 proximate the corresponding arm assembly 640 (see
Each measurement device 624 may sense or measure the angle that the corresponding arm assembly 640 rotates through as it transitions from the inactive, retracted state to the active, expanded state. More particularly, the measurement device 624 may sense or measure the angle that the arm assembly 640 rotates through as it rotates radially-outward until the wellbore engagement element contacts with the wall of the wellbore. The angle through which the arm assembly 640 rotates may range from 0° to 720° in some embodiments. In some embodiments, for instance, the angle may be less than a full revolution. For instance, the angle may range from a low of 0°, 1°, 2°, 4°, 6°, or 8° to a high of 10°, 15°, 20°, 30°, 40°, or more. For example, the angle may be between 1° and 20°, between 2° and 15°, or between 2° and 10°.
Each measurement device 624 may convert the rotary movement of the corresponding arm assembly 640 into linear or axial movement of a magnet or other positioning element (see
After the measurements are taken and/or the diameter or other geometry of the wellbore is determined, the downhole tool 600 may be actuated back into the inactive state. To actuate the downhole tool 600 into the inactive state, hydrostatic pressure of the fluid in the bore of the downhole tool 600 may be decreased (e.g., to return the pressure near the pressure within the annulus). For example, a surface fluid pump may be turned off. The pressure may decrease until the force exerted by the fluid on the piston toward the first end portion 614 of the body 610 is less than the opposing force exerted by a spring or other biasing member toward a second end portion of the body 610. When the force exerted by the spring or other biasing member becomes greater than the force exerted by the fluid, the piston may move axially toward the lower end portion of the body 610.
As the piston moves toward the lower end portion of the downhole tool 600, the engagement between the teeth (see teeth 166 of
In a more particular example shown in
Embodiments of the present disclosure may therefore relate to a system for measuring a diameter or other geometry of a wellbore. In accordance with some embodiments of the present disclosure, wellbore diameter may be obtained by using rollers or other wellbore engagement elements pushed against a wellbore wall through use of a spring or other biasing member. Arms connected to the wellbore engagement elements may rotate as the wellbore engagement elements are pushed radially-outward, and the wellbore diameter, wellbore eccentricity, or other wellbore geometry may be calculated from the rotational position of the arms. A measurement device may sense the rotation (e.g., by converting the rotational movement to axial movement of a magnet or other device), and may communicate the information with one or more sensors within an electronic or other sensing tube or device. The sensing device save the data, or may communicate with a MWD, LWD, or other downhole tool to save data for later use, to send delayed or real-time data to other devices, or to send delayed or real-time data to the surface. The data that is saved or sent may be raw measurement data or may be the calculated wellbore diameter or other geometry. Moreover, such a downhole tool may be utilized with other downhole drilling or remedial tools, and while such drilling or remedial tools are actively operating within the wellbore. In still other embodiments, components of some embodiments of the present disclosure (e.g., spring gear assemblies, measurement devices, pin slot connectors, mandrel couplings, etc.) may be used in other devices or systems other than in connection with a device for measuring wellbore geometry.
A method is disclosed for coupling components together and may include inserting a component into an aperture formed between a body and a mandrel within the body. The component may be moved axially in one direction within the aperture until a shoulder extending radially outward from the component contacts a radial surface of the body. The mandrel may also be moved axially in the first direction until a shoulder extending radially outward from the mandrel contacts the component.
According to some embodiments, the component coupled to the mandrel includes a device configured to measure wellbore geometry.
According to some embodiments, moving the mandrel axially in the first direction includes rotating a cap within the body.
According to some embodiments, the cap and mandrel are configured to be threadably engaged together.
According to some embodiments, inserting the component into the aperture includes engaging a protrusion of the component with an axial slot formed in an outer surface of the mandrel.
According to some embodiments, the shoulder extending radially-outward from the mandrel is substantially perpendicular with respect to a longitudinal axis extending through the mandrel. In other embodiments, the shoulder extending radially-outward from the mandrel is tapered at an angle from 5° to 75° with respect to a longitudinal axis.
Additional embodiments relate to a device for measuring wellbore geometry and include an arm that can rotate about an axis extending through a pivot of the arm. A gear shaft may be coupled to the pivot of the arm and can rotate in response to rotation of the arm about the axis. A position indicator may be coupled to the gear shaft in a way allowing the position indicator to move axially in response to rotation of the gear shaft.
According to some embodiments, the device for measuring wellbore geometry may further include a housing in which the gear shaft and position indicator are located.
According to some embodiments, the device for measuring wellbore geometry may include a piston coupled to the gear shaft within the housing. The piston may be movable in an axial direction in response to rotation of the gear shaft.
According to some embodiments, the device for measuring wellbore geometry may use a magnet as the position indicator, and the magnet may move in response to axial movement of the piston.
According to some embodiments, the piston may be disposed with a fluid in the housing, and the piston may cause fluid to move or be compressed so as to exert a force on the magnet, thereby causing the magnet to move in the axial direction within the housing.
According to some embodiments, a gear may be coupled to the gear shaft and configured to rotate in response to rotation of the gear shaft.
According to some embodiments, a pulley may be coupled to the gear and the position indicator. The pulley may be configured to rotate in response to rotation of the gear.
According to some embodiments, a cable may be coupled to the pulley and the position indicator, and the cable may be configured to move the position indicator axially in response to rotation of the pulley.
Devices for measuring wellbore geometry may also include a downhole tool for measuring wellbore geometry while performing drilling or remedial operations. A body may define a bore passing through a full or partial portion of the body, and a mandrel may be positioned in the bore. A measurement device may be located between the body and the mandrel, and may include a housing, a gear shaft in the housing, and a position indicator within the housing and which moves linearly in response to rotation of the gear shaft. An arm may also be coupled to an end portion of the gear shaft to rotate about an axis and cause the gear shaft to rotate.
According to some embodiments, an arm may be configured to rotate radially outward from the body and into contact with a wall of a wellbore, and linear movement of the position indicator may be proportional or otherwise related to extent of the radially outward movement of the arm and/or to the wellbore geometry.
According to some embodiments, a gear is coupled to the gear shaft and rotates in response to rotation of the gear shaft, while a pulley is coupled to the gear and rotates in response to rotation of the gear.
According to some embodiments, a cable is coupled to the pulley and position indicator and moves the position indicator linearly as the pulley rotates.
According to some embodiments, there may be multiple measurement devices and the downhole tool may include two measurement devices circumferentially offset from each other about the mandrel. A position indicator of one measurement device may be in a first zone while a position indicator of a second measurement device may be in a second zone that is axially offset from the first zone.
In the description herein, various relational terms are provided to facilitate an understanding of various aspects of some embodiments of the present disclosure. Relational terms such as “bottom,” “below,” “top,” “above,” “back,” “front,” “left”, “right”, “rear”, “forward”, “up”, “down”, “horizontal”, “vertical”, “clockwise”, “counterclockwise,” “upper”, “lower”, and the like, may be used to describe various components, including their operation and/or illustrated position relative to one or more other components. Relational terms do not indicate a particular orientation for each embodiment within the scope of the description or claims. For example, a component of a BHA that is “below” another component may be more downhole while within a vertical wellbore, but may have a different orientation during assembly, when removed from the wellbore, or in a deviated borehole. Accordingly, relational descriptions are intended solely for convenience in facilitating reference to various components, but such relational aspects may be reversed, flipped, rotated, moved in space, placed in a diagonal orientation or position, placed horizontally or vertically, or similarly modified. Relational terms may also be used to differentiate between similar components; however, descriptions may also refer to certain components or elements using designations such as “first,” “second,” “third,” and the like. Such language is also provided merely for differentiation purposes, and is not intended limit a component to a singular designation. As such, a component referenced in the specification as the “first” component may for some but not all embodiments be the same component that referenced in the claims as a “first” component.
Furthermore, to the extent the description or claims refer to “an additional” or “other” element, feature, aspect, component, or the like, it does not preclude there being a single element, or more than one, of the additional element. Where the claims or description refer to “a” or “an” element, such reference is not be construed that there is just one of that element, but is instead to be inclusive of other components and understood as “one or more” of the element. It is to be understood that where the specification states that a component, feature, structure, function, or characteristic “may,” “might,” “can,” or “could” be included, that particular component, feature, structure, or characteristic is provided in some embodiments, but is optional for other embodiments of the present disclosure. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with,” “integral with,” or “in connection with via one or more intermediate elements or members.”
Although various example embodiments have been described in detail herein, those skilled in the art will readily appreciate in view of the present disclosure that many modifications are possible in the example embodiments without materially departing from the present disclosure. Accordingly, any such modifications are intended to be included in the scope of this disclosure. Likewise, while the disclosure herein contains many specifics, these specifics should not be construed as limiting the scope of the disclosure or of any of the appended claims, but merely as providing information pertinent to one or more specific embodiments that may fall within the scope of the disclosure and the appended claims. Any described features from the various embodiments disclosed may be employed in combination. In addition, other embodiments may also be devised which lie within the scopes of the disclosure and the appended claims. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.
While embodiments disclosed herein may be used in an oil, gas, or other hydrocarbon exploration or production environment, this environment merely illustrates one environment in which embodiments of the present disclosure may be used. Systems, tools, assemblies, methods, and other components discussed herein, or which would be appreciated in view of the disclosure herein, may be used in other applications and environments, including in automotive, aquatic, aerospace, hydroelectric, or even other downhole environments. The terms “wellbore,” “borehole,” and the like are therefore also not intended to limit embodiments of the present disclosure to a particular industry or environment. A wellbore or borehole may, for instance, be used for oil and gas production and exploration, water production and exploration, mining, utility line placement, or myriad other applications.
Certain embodiments and features may have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges may appear in the description and/or one or more claims. Any numerical value is “about” or “approximately” the indicated value, and takes into account experimental error and variations that would be expected by a person having ordinary skill in the art.
Claims
1. A downhole tool for measuring wellbore geometry, comprising:
- a body having a bore extending at least partially therethrough, the body also having an aperture formed radially therein;
- an arm having a first end portion movably coupled to the body, the arm being pivotable between a retracted position in which the arm is within the aperture and an expanded position in which the arm is at least partially radially-outward relative to the body;
- a measurement device coupled to the body and configured to measure a pivoting motion of the arm; and
- a piston disposed in the bore of the body and movably coupled to a second end portion of the arm, the piston responsive to hydraulic pressure to cause the arm to pivot between the retracted position and the expanded position.
2. The downhole tool of claim 1, the arm being configured to pivot through an angle between 1° and 20°.
3. The downhole tool of claim 1, the arm being configured to contact a wall of a wellbore when in the expanded position.
4. The downhole tool of claim 3, further comprising:
- a roller coupled to the arm, the roller being configured to contact the wall of the wellbore when the arm is in the expanded position.
5. The downhole tool of claim 1, the measurement device including a magnet configured to move axially within the measurement device.
6. The downhole tool of claim 5, further comprising:
- an electronic device coupled to the body, the electronic device including a magnetometer.
7. The downhole tool of claim 6, the magnetometer being configured to measure a distance that the magnet moves.
8. The downhole tool of claim 5, the magnet being configured to move axially a distance proportional to a pivoting rotation of the arm.
9. The downhole tool of claim 8, the measurement device being configured to use the pivoting rotation of the arm to determine the diameter of a wellbore.
10. The downhole tool of claim 1, the arm being biased toward the configured to be positioned radially-inward from an outer surface of the body when in the retracted position in the aperture and at least partially radially-outward relative to the outer surface of the body when in the expanded position.
11. A tool for measuring geometry, comprising:
- a body having an axial bore extending at least partially therethrough;
- a piston coupled to the body and configured to move axially within the body from a first position to a second position when hydraulic pressure of a fluid in the bore is increased;
- a spring gear assembly coupled to the piston and configured to rotate when the piston moves between the first position and the second position;
- an arm coupled to the body and the spring gear assembly and configured to move radially relative to the body when the spring gear assembly rotates; and
- a measuring device coupled to the arm and configured to measure the movement of the arm.
12. The tool of claim 11, the piston including a shaft having plurality of teeth coupled thereto and axially spaced along the shaft, the spring gear assembly including a gear having a plurality of teeth coupled thereto and circumferentially spaced around at least a portion of the gear, the plurality of teeth of the gear being configured to engage the plurality of teeth of the shaft.
13. The tool of claim 12, the piston being configured to use engagement of the plurality of teeth of the shaft with the plurality of teeth of the gear to convert the axial movement of the piston to rotational movement of the gear when the piston moves between the first position and the second position.
14. The tool of claim 13, further comprising:
- a connector coupled to and disposed between the arm and the spring gear assembly, the connector configured to pivot the arm radially when the piston moves between the first position and the second position.
15. The tool of claim 11, the measuring device being configured to use the measured movement of the arm to determine a diameter of a wellbore.
16. A method for measuring a diameter of a wellbore while performing a downhole drilling or remedial operation, comprising:
- increasing a pressure of a fluid in a bore that extends through a body of a downhole tool within a wellbore;
- moving a piston axially within the body from a first position to a second position in response to the increased pressure in the bore;
- pivoting an arm movably coupled to the body radially-outward in response to the piston moving from the first position to the second position;
- sensing the pivoting of the arm with a measuring device coupled to the arm while drilling or performing a remedial operation; and
- determining a diameter of the wellbore based upon the pivoting of the arm.
17. The method of claim 16, wherein pivoting the arm comprises:
- rotating a gear to the body in response to the piston moving from the first position to the second position; and
- pivoting the arm radially-outward in response to the rotation of the gear.
18. The method of claim 16, wherein determining the diameter of the wellbore comprises:
- moving a magnet axially a distance proportional to an amount by which the arm pivots; and
- determining the diameter of the wellbore based upon the axial distance the magnet moves.
19. The method of claim 16, further comprising:
- contacting a wall of the wellbore with a roller coupled to the arm when the arm is positioned radially-outward from the body.
20. The method of claim 19, further comprising:
- rotating the downhole tool while the arm is positioned radially-outward from the body such that the roller rolls along the wall of the wellbore.
Type: Application
Filed: Mar 13, 2014
Publication Date: Feb 4, 2016
Applicant: SMITH INTERNATIONAL, INC. (Houston, TX)
Inventors: Jianbing Hu (Houston, TX), James Layne Larsen (Spring, TX), Tommy G. Ray (Houston, TX), Dwayne P. Terracina (Spring, TX), Rui Gao (Spring, TX), Jennifer L. Pereira (The Woodlands, TX), Weixiong Wang (Houston, TX), Ming Zhang (Spring, TX), Zhenbi Su (Spring, TX), Baozhong Yang (Pearland, TX), Siqi Xu (Houston, TX), Sudarsanam Chellappa (Houston, TX), Vishal Saheta (Houston, TX), Robert Utter (Sugar Land, TX)
Application Number: 14/777,078