INDIRECT FORCE MEASUREMENT ON A MOVEABLE ELEMENT IN A DOWNHOLE TOOL

Description

TECHNICAL FIELD

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.

BACKGROUND

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.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of the disclosure may be better understood by referencing the accompanying drawings.

FIG. 1 is an illustration depicting an example well system, according to some implementations.

FIGS. 2A-2B are schematics depicting an example drill bit, according to some implementations.

FIG. 3 is a schematic depicting an example drill bit, according to some implementations.

FIG. 4 is a schematic depicting an example drill bit, according to some implementations.

FIG. 5 is a schematic depicting an example drill bit, according to some implementations.

FIG. 6 is a schematic depicting an example drill bit, according to some implementations.

FIG. 7 is a schematic depicting an example drill bit, according to some implementations.

FIG. 8 is a schematic depicting an example drill bit, according to some implementations.

FIG. 9 is a flowchart depicting example operations for indirectly determining a force on an element of a downhole tool, according to some implementations.

FIG. 10 is a block diagram depicting an example computer, according to some implementations.

DESCRIPTION

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.

Example System

FIG. 1 is a schematic depicting an example well system, according to some implementations. In particular, FIG. 1 is a schematic diagram of a well system 100 that includes a drill string 106 having a drill bit 112 disposed in a wellbore 180 for drilling the wellbore 180 in the subsurface formation 108. 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 bit 112 forming the wellbore 180 may 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 system 100 may further include a drilling platform 110 that supports a derrick 152 having a traveling block 114 for raising and lowering the drill string 106. The drill string 106 may include, but is not limited to, drill pipe, drill collars, and downhole tools 116. The downhole tools 116 may 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 112, any one or more of the downhole tools 116 may be configured with components to determine the forces acting on elements of the respective downhole tools 116. A kelly 115 may support the drill string 106 as it may be lowered through a rotary table 118. While FIG. 1 is described relative to a drill bit 112, aspects of the disclosure may be applied to any downhole cutting structure or multiple downhole cutting structures. For instance, the drill bit 112 may include roller cone bits, polycrystalline diamond compact (PDC) bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As the drill bit 112 rotates, it may crush or cut rock to create and extend a wellbore 180 that penetrates various subterranean formations. The drill bit 112 may be rotated by various methods including rotation by a downhole mud motor and/or via rotation of the drill string 106 from the surface 120 by the rotary table 118. A pump 122 may circulate drilling fluid through a feed pipe 124 to the kelly 116, downhole through interior of the drill string 106, through orifices in the drill bit 112, back to the surface 120 via an annulus surrounding the drill string 106, and into a retention pit 128. Parameters of drilling the wellbore 180 may be adjusted to increase, decrease, and/or maintain the rate of penetration (ROP) of the drill bit 112 through the subsurface formation 108. Drilling parameters may include parameters measured at the surface 120 including weight-on-bit (WOB), torque-on-bit (TOB), rotations-per-minute (RPM) of the drill string 106, etc. In some implementations, the downhole tools 116 may include sensors to obtain downhole drilling data as the drill bit 112 drills the subsurface formation 108. The drilling data obtained from the sensors may include downhole WOB, downhole TOB, downhole RPM, drill bit vibration, etc.

The well system 100 includes a computer 170 that may be communicatively coupled to other parts of the well system 100. The computer 170 can be local or remote to the drilling platform 110. A processor of the computer 170 may perform simulations (as further described below). In some embodiments, the processor of the computer 170 may control drilling operations of the well system 100 or subsequent drilling operations of other wellbores. For instance, the processor of the computer 170 may determine forces acting on one or more elements of the drill bit 112 based on pressure measurements obtained by a pressure measurement device while the drill bit 112 drills the wellbore 180 in the subsurface formation 108. In some implementations, the processor of the computer 170 may perform a drilling operation based on the forces acting on the elements. An example of the computer 170 is depicted in FIG. 10, which is further described below.

Example Drill Bit

Example elements of a drill bit are now described. The example drill bits are described in reference to the drill bit 112 of FIG. 1. 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 in FIGS. 3-8 include 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.

FIGS. 2A-2B are schematics depicting an example drill bit, according to some implementations. In particular, FIGS. 2A-2B depict an example drill bit 200. The drill bit 200 can be an example of the drill bit 112 of FIG. 1. As shown in this example, the drill bit 200 includes six blades 202-207, which can be integrally formed and extend from a drill bit body 208. The blades 202-207 are separated by flow channels 209 that may include nozzles (i.e., orifices) where drilling mud can be ejected through the drill bit 200 and into the wellbore. Primary cutters 210, backup cutters 211, and depth of cut controllers (DOCCs) may be mounted on the blades 202-207. During drilling, the face of the primary cutters 210 and backup cutters 211 can 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 cutters 210 may be extended a greater distance from the blades 202-207 than the backup cutters 211 such that only the primary cutters 210 can be in contact with the rock of the subsurface formation. During drilling, the primary cutters 210 may become worn or broken such that one or more of the backup cutters 211 can 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 200. 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 bit 200 may drill. Pads 214 may extend from the side of the blades 202-207. The pads 214 may help maintain the size of the wellbore to a full gauge diameter, particularly when cutters become dull and become under gauge.

FIG. 3 is a schematic depicting an example drill bit, according to some implementations. In particular, FIG. 3 includes a side cross sectional view of a drill bit 300. The drill bit 300 includes a drill bit body 302 (similar to the drill bit body 208 of FIG. 2). The drill bit 300 depicted in FIG. 3 includes buttons 304 and 330. The buttons 304, 330 may not be fixed to the drill bit body 302, but rather may be moveable. For example, the button 304 may be positioned in a bore formed on the drill bit body 302 that may allow the button 304 to shift radially towards and away from the central axis 332 of the drill bit 300. In some implementations, a retaining pin 306 may be positioned through the button 304 to limit the movement of the button 304 and/or to prevent the button from falling out of the drill bit body 302. In some implementations, the buttons 304, 330 may be configured with a bias component 308, such as a spring. The bias component may apply force to button 304 such that button 304 may be pushed radially outwards from the central axis 332. The button 304 may move radially towards the central axis 332 when a force greater than the force of the bias component 308 is applied to the button 304. For example, when the drill bit 300 is drilling a wellbore, the wellbore wall (i.e., the rock of the subsurface formation) may contact the outer face of the drill bit body 302 and the button 304, thus applying a force onto the button 304. The button 304 may shift if/when the force applied to the button 304 is greater than the force applied by the bias component 308 (and any other forces acting on the button 304, such as fluid pressure in the fluid passage 316, as described below). In some implementation, one or more sensors may be positioned on each of the buttons 304, 330 to measure the distance each button 304, 330 may move.

The drill bit body 302 may be configured with passages 312 and 318. The passages 312 and 318 may intersect with each other. A pressure transducer 310 may be positioned in the passage 312 and a cap 314 may seal the passage 312 such that there is no hydraulic communication between the outside of the drill bit 300 and the passage 312. A pin 322 may be positioned in the passage 318. The pressure transducer 310 may be positioned in the passage 318 such that the pin 322 may pass through the pressure transducer 310 to hold the pressure transducer 310 in position in the passage 312. A cap 320 may seal the passage 318 such that there is no hydraulic communication between the outside of the drill bit 300 and the passage 318. In some implementations, the passages 312 and 318 may be hydraulically isolated from each other via the pressure transducer 310. In some implementations, the passage 318 may be utilized to fill the fluid passage 316 with fluid.

The drill bit body 302 may be configured with a fluid passage 316 between the button 304 and the pressure transducer 310. The fluid passage 316 may hydraulically couple the button 304 with the pressure transducer 310. The fluid passage 316 may be filled with any suitable fluid, such as hydraulic fluid. In some implementations, the fluid passage 316 may be filled with fluid to prevent the button 304 from moving radially inward. For example, the fluid pressure in the fluid passage 316 and the force of the bias component 308 may restrict the button 304 from moving radially towards the central axis 332. The pressure transducer 310 may measure the pressure in the fluid passage 316. When a force is applied to the outer face of the button 304 (such as when the outer face of the drill bit body 302/button 304 contacts the wellbore wall), the force may squeeze the fluid in the fluid passage 316, via the button 304. Thus, the pressure of the fluid in the fluid passage 316 may increase as a result of the squeeze. The pressure transducer 310 may measure the pressure of the fluid in the fluid passage 316 as the pressure increases due to the force applied to the button 304. 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 316, as obtained from the pressure transducer 310, may be utilized to determine the force applied to the button 304. For example, the force may be quantified based on the pressure in the fluid passage 316 and the area of the face of the button 304 where the force was applied. In some implementations, other factors may be accounted for in determining the force on the button 304 such as the force applied to the button 304 by the bias component 308, the hydrostatic pressure of the environment external to the drill bit 300 (i.e., the wellbore pressure), etc. Thus, the force on the button 304 may 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.

FIG. 3 depicts a pressure transducer 310 for a corresponding button 304. In some implementations, each element (such as a button 304, 330) on a drill bit (or any other suitable downhole tool) may have a corresponding pressure transducer hydraulically coupled by a fluid passage. For example, button 330 may have a corresponding pressure transducer, where the button 330 and corresponding pressure transducer are hydraulically coupled by a fluid passage different than fluid passage 316. 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 304, 330 may be hydraulically coupled to a single pressure transducer 310, 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.

FIG. 4 is a schematic depicting an example drill bit, according to some implementations. In particular, FIG. 4 includes a bottom cross sectional view of a drill bit 400. The drill bit 400 includes a drill bit body 402 (similar to the drill bit body 208 of FIG. 2). The drill bit 400 includes buttons 404-414 positioned on the sides of the drill bit 400 (similar to the buttons 304 and 330 of FIG. 3). The button 404 depicts a retaining pin 416 positioned in the button 404 to prevent the button 404 from falling out of the drill bit body 402. The drill bit body 402 may be configured with a fluid passage 418 to hydraulically couple the button 404 to a pressure measurement device (not pictured). Similar to the drill bit 300 of FIG. 3, the fluid passage 418 and pressure measurement device may be utilized to indirectly determine the force applied on the button 404 by an external force (such as the wellbore wall).

FIG. 5 is a schematic depicting an example drill bit, according to some implementations. In particular, FIG. 5 includes a side cross sectional view of a drill bit 500. The drill bit 500 includes a drill bit body 502 (similar to the drill bit body 208 of FIG. 2). The drill bit 500 includes electronics pocket 504 and 506. The electronics pockets 504 and 506 may be electrically coupled with each other. Alternatively, or in addition to, the electronics pockets 504 and 506 may be electrically coupled with a pressure measurement device (not pictured) configured to measure the pressure in a fluid passage (not pictured), as described in FIGS. 3-4.

In some implementations, the electronic pocket 506 may include a printed circuit board (PCB) assembly that may be electrically coupled to the pressure measurement devices and/or the electronic pocket 504. In some implementations, the electronic pocket 504 may include a battery that may be electrically coupled to the PCB assembly of the electronic pocket 506 and/or the pressure measurement devices. In some implementations, each electronic pocket 504 and 506 may include a strain puck that may measure the strain on the drill bit 500 at the corresponding location on the drill bit 500. In some implementations, the electronics pocket 506 and/or electronics pocket 504 may be electrically coupled with a computer, such as computer 170 of FIG. 1.

FIG. 6 is a schematic depicting an example drill bit, according to some implementations. In particular, FIG. 6 includes a partial side cross sectional view of a drill bit 600. The drill bit 600 includes a drill bit body 602 (similar to the drill bit body 208 of FIG. 2). Similar to FIGS. 3-5, a fluid passage 608 may hydraulically couple a button 604 with a pressure transducer 606. The pressure transducer 606 may be positioned in a passage 610. Similar to FIG. 5, the drill bit 600 may include electronic pockets 612 and 614. A passage 618 in the drill bit body 602 may function as a conduit for one or more wires to electrically couple the electronic pockets 612 and 614. A passage 616 may be positioned in between, and intersect with passages 610 and 618. Passage 616 may function as a conduit for one or more wires to electrically couple the electronic pockets 612 and 614 with the pressure transducer.

FIG. 7 is a schematic depicting an example drill bit, according to some implementations. In particular, FIG. 7 includes a partial side cross sectional view of a drill bit 700. The drill bit 700 includes a drill bit body 702 (similar to the drill bit body 208 of FIG. 2). Similar to FIGS. 3-6, a fluid passage 708 may hydraulically couple a button 704 with a pressure transducer 706. The pressure transducer 706 may be positioned in a passage 714 and a cap 716 may hydraulically isolate the passage 714 and the external environment of the drill bit 700. A passage 712 intersects the fluid passage 708 and may be utilized to fill the fluid passage 708 up with a fluid and/or for a pin to be positioned in such that the pin may hold the pressure transducer 706 in place in the passage 714. A passage 720 may intersect with the passage 714. One or more wires may be positioned in the passage 720 and passage 714 to electrically couple an electronic puck 718 with the pressure transducer 706.

FIG. 8 is a schematic depicting an example drill bit, according to some implementations. In particular, FIG. 8 includes a partial schematic of a drill bit 800. The drill bit 800 includes a drill bit body 802 (similar to the drill bit body 208 of FIG. 2). The drill bit 800 may have a similar configuration as the drill bits 200-700 described in FIGS. 2A-2B-FIG. 7, respectively. For example, a fluid passage 816 may hydraulically couple a button 710 with a pressure transducer 818. The pressure transducer 818 may be positioned in a passage 820 and a cap 821 may hydraulically isolate the passage 820 and the external environment of the drill bit 800. A passage 814 intersects the fluid passage 816 and 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 transducer 818 in place in the passage 820. A passage 826 may intersect with the passage 820. One or more wires may be positioned in the passage 826 and passage 820 to electrically couple electronic pucks 822 and 824 with the pressure transducer 818. The drill bit 800 also includes buttons 804-810 that are not configured with a fluid passage and/or a pressure transducer.

Example Operations

Examples operations are now described.

FIG. 9 is a flowchart depicting example operations for indirectly determining a force on an element of a downhole tool, according to some implementations. FIG. 9 depicts a flowchart 900 of 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 flowchart 900 are described in reference to the drill bits 200-800 described in FIGS. 2-8, respectively. Additionally, the operations of the flowchart 900 are described in reference to the processor of the computer 170 of FIG. 1. The operations described in the flowchart 900 may be performed for any suitable elements on a downhole tool to be positioned in a wellbore.

At block 902, 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 904, the processor of the computer 170 may 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 906, the processor of the computer 170 may 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.

Example Computer

FIG. 10 is a block diagram depicting an example computer, according to some implementations. FIG. 6 depicts a computer 1000 for determining rock elastic properties of a subsurface formation. The computer 1000 includes a processor 1001 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer 1000 includes memory 1007. The memory 1007 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 1000 also includes a bus 1003 and a network interface 1005. The computer 1000 can communicate via transmissions to and/or from remote devices via the network interface 1005 in 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 computer 1000 also includes a signal processor 1011 and a controller 1015 which may perform the operations described herein. For example, the signal processor 1011 may obtain measurements of the pressure of a fluid in a fluid passage. The signal processor 1011 may also determine the force on an element based on the pressure of the fluid. The controller 1015 may execute one or more actions based on the forces on the element. The signal processor 1011 and the controller 1015 can be in communication. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 1001. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 1001, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 10 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 1001 and the network interface 1005 are coupled to the bus 1003. Although illustrated as being coupled to the bus 1003, the memory 1007 may be coupled to the processor 1001.

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.

EXAMPLE IMPLEMENTATIONS

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.

Implementation #8: The method of any one or more of Implementation #1-7, wherein the downhole tool includes a drill bit, a stabilizer, or a reamer.

Implementation #9: The method of any one or more of Implementation #1-8, wherein the one or more elements include a button, a cutter, a depth of cut control, or any combination thereof.

Implementation #10: The method of any one or more of Implementation #1-9 further comprising: designing one or more downhole tools based on the force applied to the one or more elements.

Implementation #11: The method of any one or more of Implementation #1-10 further comprising: performing a wellbore operation based on the force applied to the one or more elements.

Implementation #12: An apparatus comprising: one or more elements of a downhole tool, wherein the downhole tool is positioned in a wellbore formed in a subsurface formation; and one or more pressure measurement devices configured to obtain measurements of a pressure of a fluid when a force is applied to the one or more elements, wherein the force applied to the one or more elements is determined based on the pressure of the fluid.

Implementation #13: The apparatus of Implementation #12, 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 #14: The apparatus of Implementation #12 or 13, 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 #15: The apparatus of any one or more of Implementation #12-14, wherein the one or more pressure measurement devices include a pressure transducer.

Implementation #16: The apparatus of any one or more of Implementation #12-15, wherein the one or more elements are not fixed on the downhole tool.

Implementation #17: The apparatus of any one or more of Implementation #12-16, wherein the downhole tool includes a drill bit, a stabilizer, or a reamer.

Implementation #18: The apparatus of any one or more of Implementation #12-17, wherein the one or more elements include a button, a cutter, a depth of cut control, or any combination thereof.

Implementation #19: A system comprising: a downhole tool to be positioned in a wellbore formed in a subsurface formation; one or more elements positioned on the downhole tool; and one or more pressure measurement devices configured to obtain measurements of a pressure of a fluid when a force is applied to the one or more elements, wherein the force applied to the one or more elements is determined based on the pressure of the fluid.

Implementation #20: The system of Implementation #19, 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.

Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed.

As used herein, the term “or” is inclusive unless otherwise explicitly noted. Thus, the phrase “at least one of A, B, or C” is satisfied by any element from the set {A, B, C} or any combination thereof, including multiples of any element.