Indirect Force Measurement on a Moveable Element in a Downhole Tool

This disclosure relation generally to the field of drilling a wellbore in a subsurface formation and more particularly to indirectly determining forces on elements of a downhole tool.

In hydrocarbon recovery operations, a downhole tools, such as a drill bit, may be utilized to form a wellbore in a subsurface formation. As the downhole tools contact the rock, forces may be applied to individual elements on the downhole tools. Downhole tools may be designed such that the individual elements may withstand the forces from the rock to form the wellbore.

The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to indirectly measuring forces on elements of a drill bit. Aspects of this disclosure can also be applied to any other downhole tools positioned in a wellbore. For clarity, some well-known instruction instances, protocols, structures, and operations have been omitted.

Example implementations relate to indirectly measuring force on one or more elements of a downhole tool. A downhole tool (such as a drill bit, stabilizer, reamer, etc.)

may include one or more elements. For example, a drill bit may include one or more buttons, cutters, depth of cut controls (DOCCs), etc. During drilling operations, measurements such as weight on bit (WOB), torque on bit (TOB), etc. may indicate the forces acting on the downhole tool. However, this is global to the tool. In some implementations, measuring the force on an element of the downhole tool may involve many assumptions. For example, conventional methods may determine the forces on each individual element of the downhole tool by some split of the total force on the downhole tool. Alternatively, forces on each element may be determined directly, where a sensor (such as a strain gauge) may be placed directly on an element. However, this may not be feasible due to the tight area restrictions in the wellbore.

In some implementations, the force on each element on a downhole tool may be indirectly determined. A downhole tool may be configured with a fluid passage filled with a fluid, such as hydraulic fluid. The downhole tool may also be configured with one or more pressure measurement devices, such as a pressure transducer. In some implementations, the fluid passage, filled with fluid, may hydraulically couple an element on the downhole tool with the pressure measurement device. For example, a button on a drill bit may be hydraulically coupled to a pressure transducer, via the fluid passage. When the downhole tool is positioned in a wellbore formed in a subsurface formation, one or more of the elements may contact the rock of the subsurface formation. Thus, a force may be applied to the element. Accordingly, the force on the element may result in a change in pressure in the fluid of the fluid passage. For example, an element may be pushed radially towards the central axis of the downhole tool as a result of the force applied to the element from the rock. The movement of the element may result in a fluid squeeze of the fluid in the fluid passage, resulting in an increase in fluid pressure. In some implementations, the pressure measurement device may measure the change in the pressure as the force is applied to the element. Accordingly, the force applied to an element may be determined in the direction of travel based on the pressure of the fluid, as measured by the pressure measurement device.

In some implementations, the forces on the one or more elements may be utilized to design elements for future hydrocarbon recovery operations. For example, when the forces are determined for buttons on a drill bit, a new drill bit may be designed for future wellbores such that there may be an increase in drilling performance and/or the drill bit may be able to last longer while drilling. In some implementations, the forces on each of the elements may be utilized to perform a wellbore operation. Wellbore operations may be stopped, started, altered, etc. For example, the forces may indicate the WOB is resulting in broken and/or damaged cutters, a decrease in rate of penetration, etc. Accordingly, the WOB may be adjusted to increase the drilling performance of the drill bit.

is a schematic depicting an example well system, according to some implementations. In particular,is a schematic diagram of a well systemthat includes a drill stringhaving a drill bitdisposed in a wellborefor drilling the wellborein the subsurface formation. While depicted for a land-based well system, example embodiments can be used in subsea operations that employ floating or sea-based platforms and rigs. The drill bitforming the wellboremay be configured with components, such as one or more fluid passages, pressure transducers, etc., to determine the forces acting on elements of the drill bit.

The well systemmay further include a drilling platformthat supports a derrickhaving a traveling blockfor raising and lowering the drill string. The drill stringmay include, but is not limited to, drill pipe, drill collars, and downhole tools. The downhole toolsmay comprise any of a number of different types of tools including measurement while drilling (MWD) tools, logging while drilling (LWD) tools, mud motors, and others. Similar to the drill bit, any one or more of the downhole toolsmay be configured with components to determine the forces acting on elements of the respective downhole tools. A kellymay support the drill stringas it may be lowered through a rotary table. Whileis described relative to a drill bit, aspects of the disclosure may be applied to any downhole cutting structure or multiple downhole cutting structures. For instance, the drill bitmay include roller cone bits, polycrystalline diamond compact (PDC) bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As the drill bitrotates, it may crush or cut rock to create and extend a wellborethat penetrates various subterranean formations. The drill bitmay be rotated by various methods including rotation by a downhole mud motor and/or via rotation of the drill stringfrom the surfaceby the rotary table. A pumpmay circulate drilling fluid through a feed pipeto the kelly, downhole through interior of the drill string, through orifices in the drill bit, back to the surfacevia an annulus surrounding the drill string, and into a retention pit. Parameters of drilling the wellboremay be adjusted to increase, decrease, and/or maintain the rate of penetration (ROP) of the drill bitthrough the subsurface formation. Drilling parameters may include parameters measured at the surfaceincluding weight-on-bit (WOB), torque-on-bit (TOB), rotations-per-minute (RPM) of the drill string, etc. In some implementations, the downhole toolsmay include sensors to obtain downhole drilling data as the drill bitdrills the subsurface formation. The drilling data obtained from the sensors may include downhole WOB, downhole TOB, downhole RPM, drill bit vibration, etc.

The well systemincludes a computerthat may be communicatively coupled to other parts of the well system. The computercan be local or remote to the drilling platform. A processor of the computermay perform simulations (as further described below). In some embodiments, the processor of the computermay control drilling operations of the well systemor subsequent drilling operations of other wellbores. For instance, the processor of the computermay determine forces acting on one or more elements of the drill bitbased on pressure measurements obtained by a pressure measurement device while the drill bitdrills the wellborein the subsurface formation. In some implementations, the processor of the computermay perform a drilling operation based on the forces acting on the elements. An example of the computeris depicted in, which is further described below.

Example elements of a drill bit are now described. The example drill bits are described in reference to the drill bitof. Although buttons of a drill bit are described herein, implementations for indirectly determining force on an element may apply to other elements on a downhole tool in a wellbore. For example, elements may also include cutters, depth of cut controllers, or any combination thereof. Downhole tools may also include stabilizers, reamers, etc.

Alternatively, or in addition to, the drill bit described ininclude one element for indirectly determining forces. More than one element on a downhole tool may be configured with a fluid passage and a pressure measurement device such that the forces on the respective elements may be determined.

are schematics depicting an example drill bit, according to some implementations. In particular,depict an example drill bit. The drill bitcan be an example of the drill bitof. As shown in this example, the drill bitincludes six blades-, which can be integrally formed and extend from a drill bit body. The blades-are separated by flow channelsthat may include nozzles (i.e., orifices) where drilling mud can be ejected through the drill bitand into the wellbore. Primary cutters, backup cutters, and depth of cut controllers (DOCCs) may be mounted on the blades-. During drilling, the face of the primary cuttersand backup cutterscan be in contact with and cut and/or shear the rock of the subsurface formation to create and extend a wellbore. In some instances, the face of the primary cuttersmay be extended a greater distance from the blades-than the backup cutterssuch that only the primary cutterscan be in contact with the rock of the subsurface formation. During drilling, the primary cuttersmay become worn or broken such that one or more of the backup cutterscan then be in contact with the rock of the subsurface formation. Many factors including orientation, shape, type, and density of the cutters may vary depending on the design of the drill bit. Other drill bit characteristics including the number of blades, the shape of the blades, etc. may vary depending on the subsurface formation environment that the drill bitmay drill. Padsmay extend from the side of the blades-. The padsmay help maintain the size of the wellbore to a full gauge diameter, particularly when cutters become dull and become under gauge.

is a schematic depicting an example drill bit, according to some implementations. In particular,includes a side cross sectional view of a drill bit. The drill bitincludes a drill bit body(similar to the drill bit bodyof). The drill bitdepicted inincludes buttonsand. The buttons,may not be fixed to the drill bit body, but rather may be moveable. For example, the buttonmay be positioned in a bore formed on the drill bit bodythat may allow the buttonto shift radially towards and away from the central axisof the drill bit. In some implementations, a retaining pinmay be positioned through the buttonto limit the movement of the buttonand/or to prevent the button from falling out of the drill bit body. In some implementations, the buttons,may be configured with a bias component, such as a spring. The bias component may apply force to buttonsuch that buttonmay be pushed radially outwards from the central axis. The buttonmay move radially towards the central axiswhen a force greater than the force of the bias componentis applied to the button. For example, when the drill bitis drilling a wellbore, the wellbore wall (i.e., the rock of the subsurface formation) may contact the outer face of the drill bit bodyand the button, thus applying a force onto the button. The buttonmay shift if/when the force applied to the buttonis greater than the force applied by the bias component(and any other forces acting on the button, such as fluid pressure in the fluid passage, as described below). In some implementation, one or more sensors may be positioned on each of the buttons,to measure the distance each button,may move.

The drill bit bodymay be configured with passagesand. The passagesandmay intersect with each other. A pressure transducermay be positioned in the passageand a capmay seal the passagesuch that there is no hydraulic communication between the outside of the drill bitand the passage. A pinmay be positioned in the passage. The pressure transducermay be positioned in the passagesuch that the pinmay pass through the pressure transducerto hold the pressure transducerin position in the passage. A capmay seal the passagesuch that there is no hydraulic communication between the outside of the drill bitand the passage. In some implementations, the passagesandmay be hydraulically isolated from each other via the pressure transducer. In some implementations, the passagemay be utilized to fill the fluid passagewith fluid.

The drill bit bodymay be configured with a fluid passagebetween the buttonand the pressure transducer. The fluid passagemay hydraulically couple the buttonwith the pressure transducer. The fluid passagemay be filled with any suitable fluid, such as hydraulic fluid. In some implementations, the fluid passagemay be filled with fluid to prevent the buttonfrom moving radially inward. For example, the fluid pressure in the fluid passageand the force of the bias componentmay restrict the buttonfrom moving radially towards the central axis. The pressure transducermay measure the pressure in the fluid passage. When a force is applied to the outer face of the button(such as when the outer face of the drill bit body/buttoncontacts the wellbore wall), the force may squeeze the fluid in the fluid passage, via the button. Thus, the pressure of the fluid in the fluid passagemay increase as a result of the squeeze. The pressure transducermay measure the pressure of the fluid in the fluid passageas the pressure increases due to the force applied to the button. Any suitable pressure measurement devices may be used to measure the fluid pressure.

In some implementations, the pressure of the fluid in the fluid passage, as obtained from the pressure transducer, may be utilized to determine the force applied to the button. For example, the force may be quantified based on the pressure in the fluid passageand the area of the face of the buttonwhere the force was applied. In some implementations, other factors may be accounted for in determining the force on the buttonsuch as the force applied to the buttonby the bias component, the hydrostatic pressure of the environment external to the drill bit(i.e., the wellbore pressure), etc. Thus, the force on the buttonmay be indirectly determined via the pressure of the fluid in the fluid passage. In some implementations, the element force may be measured with a load cell coupled with the element.

depicts a pressure transducerfor a corresponding button. In some implementations, each element (such as a button,) on a drill bit (or any other suitable downhole tool) may have a corresponding pressure transducer hydraulically coupled by a fluid passage. For example, buttonmay have a corresponding pressure transducer, where the buttonand corresponding pressure transducer are hydraulically coupled by a fluid passage different than fluid passage. In some implementations, more than one element on a downhole tool may be hydraulically coupled via a single fluid passage, and have a corresponding pressure transducer to measure the pressure in said fluid passage. For example, each button,may be hydraulically coupled to a single pressure transducer, via a common fluid passage. Any suitable combination of fluid passages and pressure transducers may be utilized to indirectly determine the forces acting on the elements of a downhole tool.

is a schematic depicting an example drill bit, according to some implementations. In particular,includes a bottom cross sectional view of a drill bit. The drill bitincludes a drill bit body(similar to the drill bit bodyof). The drill bitincludes buttons-positioned on the sides of the drill bit(similar to the buttonsandof). The buttondepicts a retaining pinpositioned in the buttonto prevent the buttonfrom falling out of the drill bit body. The drill bit bodymay be configured with a fluid passageto hydraulically couple the buttonto a pressure measurement device (not pictured). Similar to the drill bitof, the fluid passageand pressure measurement device may be utilized to indirectly determine the force applied on the buttonby an external force (such as the wellbore wall).

is a schematic depicting an example drill bit, according to some implementations. In particular,includes a side cross sectional view of a drill bit. The drill bitincludes a drill bit body(similar to the drill bit bodyof). The drill bitincludes electronics pocketand. The electronics pocketsandmay be electrically coupled with each other. Alternatively, or in addition to, the electronics pocketsandmay be electrically coupled with a pressure measurement device (not pictured) configured to measure the pressure in a fluid passage (not pictured), as described in.

In some implementations, the electronic pocketmay include a printed circuit board (PCB) assembly that may be electrically coupled to the pressure measurement devices and/or the electronic pocket. In some implementations, the electronic pocketmay include a battery that may be electrically coupled to the PCB assembly of the electronic pocketand/or the pressure measurement devices. In some implementations, each electronic pocketandmay include a strain puck that may measure the strain on the drill bitat the corresponding location on the drill bit. In some implementations, the electronics pocketand/or electronics pocketmay be electrically coupled with a computer, such as computerof.

is a schematic depicting an example drill bit, according to some implementations. In particular,includes a partial side cross sectional view of a drill bit. The drill bitincludes a drill bit body(similar to the drill bit bodyof). Similar to, a fluid passagemay hydraulically couple a buttonwith a pressure transducer. The pressure transducermay be positioned in a passage. Similar to, the drill bitmay include electronic pocketsand. A passagein the drill bit bodymay function as a conduit for one or more wires to electrically couple the electronic pocketsand. A passagemay be positioned in between, and intersect with passagesand. Passagemay function as a conduit for one or more wires to electrically couple the electronic pocketsandwith the pressure transducer.

is a schematic depicting an example drill bit, according to some implementations. In particular,includes a partial side cross sectional view of a drill bit. The drill bitincludes a drill bit body(similar to the drill bit bodyof). Similar to, a fluid passagemay hydraulically couple a buttonwith a pressure transducer. The pressure transducermay be positioned in a passageand a capmay hydraulically isolate the passageand the external environment of the drill bit. A passageintersects the fluid passageand may be utilized to fill the fluid passageup with a fluid and/or for a pin to be positioned in such that the pin may hold the pressure transducerin place in the passage. A passagemay intersect with the passage. One or more wires may be positioned in the passageand passageto electrically couple an electronic puckwith the pressure transducer.

is a schematic depicting an example drill bit, according to some implementations. In particular,includes a partial schematic of a drill bit. The drill bitincludes a drill bit body(similar to the drill bit bodyof). The drill bitmay have a similar configuration as the drill bits-described in-, respectively. For example, a fluid passagemay hydraulically couple a buttonwith a pressure transducer. The pressure transducermay be positioned in a passageand a capmay hydraulically isolate the passageand the external environment of the drill bit. A passageintersects the fluid passageand may be utilized to fill the fluid passage up with a fluid and/or for a pin to be positioned in such that the pin may hold the pressure transducerin place in the passage. A passagemay intersect with the passage. One or more wires may be positioned in the passageand passageto electrically couple electronic pucksandwith the pressure transducer. The drill bitalso includes buttons-that are not configured with a fluid passage and/or a pressure transducer.

Examples operations are now described.

is a flowchart depicting example operations for indirectly determining a force on an element of a downhole tool, according to some implementations.depicts a flowchartof operations to indirectly determine the force on one or more elements of a downhole tool when the downhole tool is positioned in a wellbore formed in the subsurface formation. The operations of flowchartare described in reference to the drill bits-described in, respectively. Additionally, the operations of the flowchartare described in reference to the processor of the computerof. The operations described in the flowchartmay be performed for any suitable elements on a downhole tool to be positioned in a wellbore.

At block, a downhole tool may be positioned in a wellbore. The downhole tool may include elements positioned proximate the outer face of the downhole tool such that the elements may come into contact with the rock of the subsurface formation.

At block, the processor of the computermay obtain measurements of a pressure of a fluid when a force is applied to one or more elements on the downhole tool. The pressure may be measured by a pressure measurement device, such as a pressure transducer. In some implementations, a fluid passage may hydraulically couple an element to a pressure measurement device. The pressure measurement device may measure the fluid pressure in the fluid passage when a force is applied to the respective element or elements.

In some implementations, only one element may be configured with a pressure measurement device and fluid passage, and/or more than one element may be configured with a pressure measurement device and fluid passage. For example, 2 buttons on a drill bit may each have a corresponding fluid passage and pressure transducer, a button and a cutter may each have a corresponding fluid passage and pressure transducer, every element may have a corresponding fluid passage and pressure transducer, etc. In some implementations, a fluid passage may hydraulically couple a group of elements to a pressure measurement device. For example, a single pressure transducer may be hydraulically coupled to all buttons on a drill bit. Any suitable configuration of elements, pressure measurement devices, and fluid passages may be utilized on the downhole tool.

At block, the processor of the computermay determine the force applied to the one or more elements based on the pressure of the fluid. When a force is applied to an element (such as when the element contacts the rock in the subsurface formation), the force may be transferred to the fluid in the corresponding fluid passage, resulting in a squeeze of the fluid. The fluid pressure in the fluid passage and the cross sectional area of the element where the force may be applied may be utilized to determine the force applied to the element. In some implementations, other factors may be considered when determining the force such as the force of a bias component (if present) on the element, the hydrostatic pressure of the wellbore, etc.

While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for indirectly determining forces on one or more elements of a downhole tool herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

Various modifications to the implementations described in this disclosure may be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other implementations without departing from the spirit or scope of this disclosure. Thus, the claims are not intended to be limited to the implementations shown herein but are to be accorded the widest scope consistent with this disclosure, the principles and the novel features disclosed herein.

Certain features that are described in this specification in the context of separate implementations also may be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation also may be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination may in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.

Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. Further, the drawings may schematically depict one more example process in the form of a flow diagram. However, some operations may be omitted and/or other operations that are not depicted may be incorporated in the example processes that are schematically illustrated. For example, one or more additional operations may be performed before, after, simultaneously, or between any of the illustrated operations. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described should not be understood as requiring such separation in all implementations, and the described program components and systems may generally be integrated together in a single software product or packaged into multiple software products. Additionally, other implementations are within the scope of the following claims. In some cases, the actions recited in the claims may be performed in a different order and still achieve desirable results.

Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally away from the bottom, terminal end of a well; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” or other like terms shall be construed as generally toward the bottom, terminal end of the well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. In some instances, a part near the end of the well can be horizontal or even slightly directed upwards. Unless otherwise specified, use of the term “subsurface formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.

is a block diagram depicting an example computer, according to some implementations.depicts a computerfor determining rock elastic properties of a subsurface formation. The computerincludes a processor(possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computerincludes memory. The memorymay be system memory or any one or more of the above already described possible realizations of machine-readable media. The computeralso includes a busand a network interface. The computercan communicate via transmissions to and/or from remote devices via the network interfacein accordance with a network protocol corresponding to the type of network interface, whether wired or wireless and depending upon the carrying medium. In addition, a communication or transmission can involve other layers of a communication protocol and or communication protocol suites (e.g., transmission control protocol, Internet Protocol, user datagram protocol, virtual private network protocols, etc.).

The computeralso includes a signal processorand a controllerwhich may perform the operations described herein. For example, the signal processormay obtain measurements of the pressure of a fluid in a fluid passage. The signal processormay also determine the force on an element based on the pressure of the fluid. The controllermay execute one or more actions based on the forces on the element. The signal processorand the controllercan be in communication. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in(e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processorand the network interfaceare coupled to the bus. Although illustrated as being coupled to the bus, the memorymay be coupled to the processor.

While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for determining rock elastic properties as described herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

Various modifications to the implementations described in this disclosure may be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other implementations without departing from the spirit or scope of this disclosure. Thus, the claims are not intended to be limited to the implementations shown herein but are to be accorded the widest scope consistent with this disclosure, the principles and the novel features disclosed herein.

Certain features that are described in this specification in the context of separate implementations also may be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation also may be implemented in multiple implementations separately or in any suitable sub combination. Moreover, although features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination may in some cases be excised from the combination, and the claimed combination may be directed to a sub combination or variation of a sub combination.

Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. Further, the drawings may schematically depict one more example process in the form of a flow diagram. However, some operations may be omitted and/or other operations that are not depicted may be incorporated in the example processes that are schematically illustrated. For example, one or more additional operations may be performed before, after, simultaneously, or between any of the illustrated operations. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described should not be understood as requiring such separation in all implementations, and the described program components and systems may generally be integrated together in a single software product or packaged into multiple software products. Additionally, other implementations are within the scope of the following claims. In some cases, the actions recited in the claims may be performed in a different order and still achieve desirable results.

Implementation #1: A method comprising: obtaining, via one or more pressure measurement devices, measurements of a pressure of a fluid when a force is applied to one or more elements of a downhole tool positioned in a wellbore formed in a subsurface formation; and determining the force applied to the one or more elements based on the pressure of the fluid.

Implementation #2: The method of Implementation #1, wherein the downhole tool includes a fluid passage filled with the fluid, and wherein the fluid passage hydraulically couples a first element and a first pressure measurement device.

Implementation #3: The method of Implementation #2 further comprising: obtaining measurements of the fluid in the fluid passage when a force is applied to the first element, wherein the force causes a squeeze in the fluid in the fluid passage.

Implementation #4: The method of any one or more of Implementation #1-3, wherein the downhole tool includes a fluid passage filled with the fluid, and wherein a first pressure measurement device is hydraulically coupled with a plurality of elements, via a fluid passage.

Implementation #5: The method of any one or more of Implementation #1-4, wherein the one or more pressure measurement devices include a pressure transducer.

Implementation #6: The method of any one or more of Implementation #1-5, wherein the one or more elements are not fixed on the downhole tool.

Implementation #7: The method of any one or more of Implementation #1-6, wherein the fluid includes hydraulic fluid.