Patent Application
20250215755
Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations that may be located onshore or offshore. The development of subterranean operations and the processes involved in removing hydrocarbons from a subterranean formation may be complex. Typically, subterranean operations involve a number of different steps such as, for example, drilling a wellbore, at a desired well site, treating the wellbore to optimize production of hydrocarbons, and performing the necessary steps to produce and process the hydrocarbons from the subterranean formation.
Drilling a wellbore may include introducing a drill bit into the formation and rotating the drill bit to extend the wellbore. In certain operations, it may be necessary to control the direction in which the wellbore is being extended by altering the axis of the drill bit with respect to the wellbore. This is typically accomplished using complex mechanisms that increase the costs associated with the drilling operation.
Embodiments of the disclosure may be better understood by referencing the accompanying drawings.
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. In some instances, well-known instruction instances, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description.
Certain systems and methods are discussed below in the context of petroleum drilling and production operations in which information is acquired relating to parameters and conditions downhole. Several methods exist for downhole information collection, including logging-while-drilling (“LWD”) and measurement-while-drilling (“MWD”). In LWD, data is typically collected during the drilling process, thereby avoiding any need to remove the drilling assembly to insert a wireline logging tool. LWD consequently allows the driller to make accurate real-time modifications or corrections to optimize performance while minimizing downtime. MWD is the term for measuring conditions downhole concerning the movement and location of the drilling assembly while the drilling continues. LWD concentrates more on formation parameter measurement. While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term MWD will be used with the understanding that this term encompasses both the collection of formation parameters and the collection of information relating to the movement and position of the drilling assembly.
Stiffness is an important parameter that is a factor in the Dog Leg Severity (DLS) performance of a bottom hole assembly (BHA) in a wellbore. A lower stiffness is generally required for achieving a higher build DLS, while a higher stiffness is preferred for holding neutral DLS in vertical or lateral wellbore sections. Typically, it is the curve section which requires building or strengthening of DLS. This has previously been done by having to change out one or more subs with different parameters, or having a flex sub, a sub with a section of lower stiffness, included into BHA configurations which are intended for building DLS. This creates some challenges and limitations. Conventionally, the drill string will be pulled to add and remove the flex sub when transitioning from a vertical to curve, and curve to lateral respectively, requiring multiple pulls and reinsertions of the drill string. In addition, a stiffness value may need to be predetermined and may have to remain fixed once the tool is downhole such that the stiffness value cannot be changed or controlled while drilling. However, a great emphasis has been to be able to perform the full vertical-curve-lateral in a single run without pulling the drill string. Embodiments disclosed herein provide solutions able to achieve performing the full vertical-curve-lateral drilling in a single run without pulling the drill string.
Provided herein are disclosures of a downhole drilling tool having at least one sub with changeable and tunable/controllable stiffness without removing the drill string from the wellbore. A downhole sub or section of the downhole drilling tool may have a section where the stiffness is tunable or programmable from the surface of the wellbore. The downhole sub may utilize tunable or programmable stiffness materials. The ability to adjust the BHA stiffness from the surface without pulling the tool from downhole and out of the hole presents significant saving of time, and also saving in costs because separate flexible subs of varying stiffness are not required. Further, the added control of stiffness lessens the reliance on rotary steerable (RSS) tools for directional drilling control, which helps reduce wear and fatigue of the RSS tools and components that are typically highly stressed or worn out due to high forces applied during directional drilling, such as, e.g., the driveshaft of a point-the-bit tool or the pads on a push-the-bit tool.
In one embodiment, a metallic sub may be fabricated using stainless steel or nickel-based alloy used for downhole subs and have one or more cavities. In some embodiments, the cavities may be longitudinal cavities that extend through the length of the sub body or housing. In each of the one or more cavities there is a tunable thread comprising electro-programmable stiffness material. These tunable members or threads may be electrically connected with an electronics system of the BHA that is linked with a pulser. In some embodiments instructions from the surface of the wellbore, or a control unit associated with the BHA may be sent via pulser to adjust, increase or decrease, the stiffness of the tunable members.
In some embodiments, the cavities and tunable threads may be configured within the sub in other directions or orientations besides longitudinal; for example, the cavities may be radial, spiral, or may even be formed into a cylindrical insert that can be fitted into a corresponding cavity in a sub. In other embodiments, the cavities and threads may be distributed homogeneously or concentrated in a specific segment of the sub, depending on the downhole application. In some applications, non-unfirm stiffness may be desired.
The tunable threads may also be adjusted and controlled by ways other than electrical, such as thermal, magnetic, or pressure controlled. In other embodiments, the commands to adjust the stiffness of the threads may be received from an onboard telemetry system that has sensors to take various measurements such as inclination and azimuth of the downhole tool, and in some embodiments, the onboard telemetry system may include algorithms to determine any stiffness adjustments needed.
Programmable stiffness materials include materials whose mechanical properties, particularly their stiffness, can be adjusted or controlled electronically or programmatically. Electroprogrammable stiffness often involves the use of smart materials like piezoelectric materials, shape memory alloys, or magnetostrictive materials. These materials can change their mechanical properties (such as Young's modulus (Ey), the modulus of elasticity under tension or compression-stiffness, as used herein) in response to electrical or magnetic stimuli. Certain polymers, known as electroactive polymers (EAPs), can change their shape or mechanical properties when subjected to an electric field. A control system may be coupled with the downhole sub to adjust the electrical or magnetic fields applied to the programmable stiffness materials. These control systems may be programmed to vary the stiffness of the downhole sub according to specific requirements.
Referring now to
The wellbore system 100 comprises a derrick 108 supported by the drilling platform 102 and having a traveling block 138 for raising and lowering a drill string 114. A kelly 136 may support the drill string 114 as it is lowered through a rotary table 142 into a borehole 110. A pump 130 may circulate drilling fluid through a feed pipe 134 to kelly 136, downhole through the interior of drill string 114, through orifices in a drill bit 118, back to the surface via an annulus 140 formed by the drill string 114 and the wall of the borehole 110. Once at the surface, the drilling fluid may exit the annulus 140 through a pipe 144 and into a retention pit 132. The drilling fluid transports cuttings from the borehole 110 into the pit 132 and aids in maintaining integrity or the borehole 110.
The wellbore system 100 may comprise a bottom hole assembly (BHA) 116 coupled to the drill string 114 near the drill bit 118. The BHA 116 may comprise an LWD/MWD tool 122 and a telemetry element 120. The LWD/MWD tool 122 may include receivers and/or transmitters (e.g., antennas capable of receiving and/or transmitting one or more electromagnetic signals). As the borehole 110 is extended by drilling through the formations 106, the LWD/MWD tool 122 may collect measurements relating to various formation properties as well as the tool orientation and position and various other drilling conditions, including formation resistivity, a gamma ray device for measuring formation gamma ray intensity, devices for measuring the inclination and azimuth of the drill string 114, pressure sensors for measuring, e.g., drilling fluid pressure, temperature sensors for measuring borehole temperature, etc. The telemetry element 120 may be coupled to other elements within the BHA 116, e.g., the LWD/MWD tool 122, and may transmit data to and receive data from a control unit located at the surface via a surface transceiver 146, the data corresponding or directed to one or more of the elements within the BHA 116. The telemetry element 120 may transmit measurements or data through one or more wired or wireless communications channels (e.g., wired pipe or electromagnetic propagation). Alternatively, the telemetry element 120 may transmit data as a series of pressure pulses or modulations within a flow of drilling fluid (e.g., mud-pulse or mud-siren telemetry), or as a series of acoustic pulses that propagate to the surface through a medium, such as the drill string 114. In other embodiments, wired drill pipe, acoustic telemetry, or other telemetry technologies known in the art may be used to provide communication between the surface control unit and the telemetry element 120.
In certain embodiments, the system 100 may further comprise a downhole directional drilling system, such as a rotary steerable system (RSS) tool 150 that can control and steer direction of the downhole tool. The RSS 150 may include at least a motor and be coupled with a drilling sub 124 and the drill bit 118. In the embodiment shown, the RSS 150 and the drilling sub 124 are positioned within the BHA 116 closest to the drill bit 18. In other embodiments, the RSS 150 and the drilling sub 124 may be located in other areas along the drill string 114, including above the LWD/MWD tool 122 and telemetry element 120 in the BHA 116, and coupled to the drill string 114 above the BHA 116. The RSS 150 may rotate the drill bit 118, causing it to extend the borehole 116. In certain embodiments, the RSS 150 may include a downhole motor with fluid driven turbine that rotates in response to the flow of drilling fluid through the drill string 114. The fluid driven turbine of the downhole motor may comprise a rotor and a stator. The rotor may be coupled to and drive the drill bit 118 through a flexible drive shaft (not shown) extending through the drilling sub 124.
The drilling sub 124 may control, in part, the longitudinal axis 128 of the drill bit 118 with respect to the longitudinal axis 126 of the system 100 above the drilling sub 124. In particular, the drilling sub 124 may comprise materials having controllable or tunable stiffness. In some examples, the stiffness of the drilling sub 124 may be adjusted such that the drilling sub 124 may selectively bend to offset the longitudinal axis 128 of the drill bit 118 from the longitudinal axis 126 of the system 100 above the drilling sub 124 by an angle that corresponds to a bend angle of the drilling sub 124. The offset may occur because the bend in the drilling sub 124 is imparted to the flexible drive shaft (not shown) between the RSS 150 and drill bit 118. By offsetting the longitudinal axis 128 from the longitudinal axis 126, the drilling sub 124 may change the drilling direction of the system 100, which corresponds to the longitudinal axis 128 of the drill bit 118.
Before drilling a wellbore, BHA modelling may be run to determine various design parameters of the drilling system and drilling parameters in order to achieve directional drilling without borehole spiraling. One of the key outputs includes DLS performance of various components such that a desired stiffness, or Young's modulus (Ey) may be determined for each component. As the RSS 150 moves through the formation, the sensors of the telemetry element 120 may provide various measurements, including inclination and azimuth readings. According to aspects of the present disclosure, the stiffness of the drilling sub 124 maybe adjusted to selectively bend to increase DLS performance in response to the telemetry element 120 measurements, such as azimuth and inclination, along with a weight applied to the drill bit 118 by the wellbore system 100. This weight may be referred to as the “weight-on-bit” (WOB) and may be characterized by the weight of the elements between the drill bit 118 and the traveling block 138 less any frictional forces imparted on the drill string 114 by the borehole 110 and any weight born by the traveling block 138. The bend angle of the drilling sub 124 may be based, in part, on the WOB and the Young's module stiffness characteristics of the drilling sub 124. As the drilling sub 124 bends or moves within the wellbore, the stiffness characteristics of the drilling sub 124 may be altered to select when and how the drilling sub 124 will bend in response to the WOB, the magnitude of the bend, and the orientation of the bend with respect to the longitudinal axis 126, all while the drill string 114 remains downhole. Because the stiffness of the drilling sub 124 may be controlled and adjusted or tuned during the drilling process, the drill string 114 no longer has to be removed to change to a more flexible or stiff sub, and the stiffness value no longer has to remain fixed at a predetermined level, as previously required. This may result in both a time savings and cost savings previously associated with the additional time and cost of removing and re-inserting the drill string 114.
These measurement changes typically happen when the drilling changes direction, as discussed above, from a vertical to curve or curve to horizontal change. However, other situations may occur downhole where the stiffness of the drilling sub 124 may need to be adjusted, for example, during drilling, a drilling engineer may discover that the actual wellbore is deviating from the planned path and needs to adjust the drilling direction to get the drilling back on track. In another situation, the drilling system may unexpectedly meet with certain obstacles or hole conditions that requires the well path to deviate and the stiffness may need to be adjusted. In any of these situations, previous systems would require the drill string to be removed for the sub to be changed and then reinserted, but incorporating embodiments of the drilling sub 124 with tunable and adjustable stiffness while downhole enables adjustments to be made while the tool remains downhole resulting in at least time and cost savings.
Referring now to
The tunable members 206 may be adjusted by electrical signals, thermal activation, magnetic activation, or pressure activation. Adjustment of the stiffness of the sub 200 may be based on formation conditions and/or readings, desired direction of drilling, measurements taken downhole, such as from an MWD/LWD telemetry unit or other downhole sensors, and various other conditions that may have traditionally triggered removable of the BHA in order to change flexible subs. The tunable members 206 may be communicatively coupled, either wired or wirelessly, with an onboard electronics system of a BHA to which the sub 200 may be coupled. In some embodiments, the BHA may receive commands from the surface of the wellbore through a receiver such as a pulser for receiving downlink commands from the surface, such as illustrated in
Referring now to
Sub 200 and sub 300 are shown having one or more cavities and one or more tunable members or threads positioned substantially and/or uniformly surrounding the cavity, but other embodiments may have one or more cavities and tunable threads or members distributed homogeneously or concentrated to a specific segment or portion of the sub. And still other embodiments may have one or more cavities and tunable threads positioned in a non-uniform or non-homogenous arrangement.
Referring now to
Referring now to
The second embodiment 500B shown in
At a block 604, at least one condition is detected indicating that the stiffness of the tunable sub needs to be adjusted.
At a block 606, a stiffness of one or more tunable members of the tunable sub are adjusted based on the at least one detected condition while the tunable sub and drill string remains downhole. In some embodiments having a plurality of tunable members, the tunable members may all be adjusted to a uniform stiffness level, or different tunable members or threads may have different, non-uniform, stiffness level adjustments. For example, one or more tunable members positioned proximate a high side of the tunable sub may have a higher or lower stiffness than tunable threads positioned proximate a low side of the tunable sub.
At a block 608, drilling continues with the adjusted stiffness level to alter the well path.
At a block 610, the stiffness may be adjusted back to an initial setting to resume an original drilling direction if desired. As the drill string continues to move through the wellbore, conditions may continue to change and the stiffness of the tunable sub may be changed many times according to blocks 604-608, all while the drill string remains downhole such that the drill string does not need to be pulled uphole for any changes related to stiffness of the tunable sub.
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. 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.
The flowcharts are provided to aid in understanding the illustrations and are not to be used to limit the scope of the claims. The flowcharts depict example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations may be performed in parallel; and the operations may be performed in a different order. For example, the operations of the methods 900 or 1000 may be performed in parallel or concurrently. It will be understood that each block of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general purpose computer, special purpose computer, or other programmable machine or apparatus.
As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.
Any combination of one or more machine readable medium(s) may be utilized. The machine readable medium may be a machine readable signal medium or a machine readable storage medium. A machine readable storage medium may be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine readable storage medium would include the following: a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine readable storage medium may be any tangible medium that can contain, or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine readable storage medium is not a machine readable signal medium.
A machine readable signal medium may include a propagated data signal with machine readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device.
Program code embodied on a machine-readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.
The program code/instructions may also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or block.
The system also includes a stiffness controller 711. The stiffness controller 711 may perform one or more operations depicted in
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.
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.
Aspects disclosed herein include:
Aspect A: A downhole sub, comprising: a housing; and at least one tunable stiffness member integrated with the housing, the tunable stiffness member comprising a programmable stiffness material; wherein a stiffness of the tunable stiffness member is adjusted in response to instructions from a control unit of a wellbore system.
Aspect B: A downhole system, comprising: a tool string positioned downhole in a wellbore; a control unit; and a downhole sub coupled with the tool string and the control unit, the downhole sub comprising: a housing; and at least one tunable stiffness member integrated with the housing, the tunable stiffness member comprising a programmable stiffness material; wherein a stiffness of the tunable stiffness member is adjusted in response to instructions from the control unit.
Aspect C: A method of adjusting a stiffness of a downhole tool positioned within a wellbore, the method comprising: inserting the downhole tool into the wellbore, the downhole tool comprising: a tool string; a control unit; and a downhole sub coupled with the tool string and the control unit, the downhole sub comprising: a housing; and at least one tunable stiffness member integrated with the housing, the tunable stiffness member comprising a programmable stiffness material; wherein a stiffness of the tunable stiffness member is adjusted in response to instructions from the control unit; and wherein the stiffness of the downhole sub conforms to the stiffness of the tunable stiffness member; receiving measurements at the control unit from one or more sensors positioned on the tool string as the downhole tool moves within the wellbore; adjusting the stiffness of the tunable stiffness members based on the measurements.
Aspects A, B, and C may have one or more of the following additional elements in combination:
Element 1: wherein further comprising a cavity within the housing, wherein the at least one tunable stiffness member is positioned in the housing, wherein the cavity is a longitudinal cavity extending along a length of the housing.
Element 2: wherein the cavity is a longitudinal cavity extending along a length of the housing and wherein the tunable stiffness member is a longitudinal thread extending a length of the cavity.
Element 3: further comprising a cylindrical opening around a channel extending a length of the housing.
Element 4: wherein the tunable stiffness member is one of a cylindrical insert positioned within the cylindrical opening or a spiral thread winding through the cylindrical opening around the channel.
Element 5: further comprising a plurality of cavities and a plurality of tunable stiffness members individually positioned within the plurality of cavities.
Element 6: wherein each of the plurality of tunable stiffness members may be individually adjusted such that each tunable member may have a different stiffness.
Element 7: wherein the control unit receives input from a telemetry element of the wellbore system, and the stiffness of the at least one tunable stiffness member is adjusted based on a signal received from the control unit via a pulser.
Element 8: wherein the stiffness of the at least one tunable stiffness member is adjusted based on inclination and azimuth readings taken from sensors during an automated drilling operation.
Element 9: further comprising a cylindrical opening around a channel extending a length of the housing, and wherein the tunable stiffness member is one of a cylindrical insert positioned within the cylindrical opening or a spiral thread winding through the cylindrical opening around the channel.
Element 10: wherein the control unit is communicatively coupled with a telemetry element coupled with the tool string, wherein the control unit is configured to send a signal to adjust the stiffness of the at least one tunable stiffness member based on measurements received from the telemetry element.
Element 11: wherein the signal to adjust the stiffness of the at least one tunable stiffness member is based on inclination and azimuth readings taken from sensors during an automated drilling operation.
Element 12: wherein the control unit is configured to send a signal to adjust the stiffness of the at least one tunable stiffness member via a pulser.
Element 13: wherein the measurements include at least inclination and an azimuth of the tool string.
Element 14: wherein the downhole sub further comprises a plurality of cavities and a plurality of tunable stiffness members individually positioned within the plurality of cavities.
Element 15: wherein each of the plurality of tunable stiffness members may be individually adjusted such that each tunable member may have a different stiffness.
