HYDRAULICALLY LOCKED TOOL

Abstract

A tool with a hydraulic lock mechanism may include a body defining a flow tube and a chamber. An expandable member may be coupled to the body. A first valve may be located between the chamber and the flow tube to control the flow of fluid into the chamber from the flow tube. A second valve may located between the chamber and an external environment to control the flow of fluid from the chamber into the external environment. The first and second valves may trap fluid within the chamber to maintain the tool in an active position. A piston may be connected to the expandable member and may move in response to pressurization of the chamber. At one position, the piston may cause the expandable member to extend to a radially outward position. At another position, the piston may cause the expandable member to retract to a radially inward position.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of, and priority to, U.S. Patent Application Ser. No. 62/031,665, titled “Tool with Hydraulic Lock Mechanism,” and filed on Jul. 31, 2014, which application is expressly incorporated herein by this reference in its entirety.

BACKGROUND

In the drilling of oil and gas wells, concentric casing strings are installed and cemented in the wellbore as drilling progresses to increasing depths. Each new casing string is supported within the previously installed casing string, thereby limiting the annular area available outside the uppermost casing strings for the cementing operation. As successively smaller diameter casing strings are suspended, the flow area for the production of oil and gas inside the casing strings decreases as the distance from the surface increases.

The diameter of the wellbore below the lower end portion of the previous casing string or other locations in a wellbore may be enlarged for various reasons. For example, the diameter of the wellbore may be enlarged to provide clearance for running casing, to obtain adequate annular space in the hole for cementing, to enlarge zones for gravel pack completion or cementing, and for other purposes.

Reamers are used for enlarging the diameter of the wellbore. A reamer generally has two states. In an inactive or retracted state, the cutter blocks of the reamer are in a radially inward, retracted position and the reamer maintains a diameter small enough to pass through the existing casing strings. In an active, expanded, or deployed state, the cutter blocks are in an outward, radially extended position where the cutter blocks can be used to enlarge the diameter of the wellbore.

Changing the state of a reamer or actuating other downhole tools in a wellbore is often accomplished by dropping a ball down a bore of a drill string to break shear pins using back pressure caused by the drilling mud building up pressure behind the ball as the ball obstructs the path of the drilling mud. After the shear pins break, a valve may be free to open or actuate a downhole tool, such as a reamer. Once the valve is open, the drilling mud may be used to move the cutter blocks to the active state.

A drilling system may continually pump drilling fluid or mud down through the drilling system to the downhole tools, then out into the wellbore annulus and back up to the surface. The drilling mud may cool the downhole drilling system, flush cuttings back up to the surface, and provide pressure to hold the downhole tools in a position that facilitates operation of the tool, such as holding the cutter blocks of a reamer in an active position with enough force to ream and enlarge the wellbore. Once the drilling tool has completed an operation, such as when a wellbore has been enlarged by a reamer, the downhole tool and the drill string may be removed from the wellbore.

SUMMARY

In one non-limiting embodiment, a downhole tool for reaming a wellbore is disclosed. The downhole tool may include a body that defines a bore and a chamber. An expandable member may be coupled to the body and movable by a movable element that also moves relative to the body. The movable element may move the expandable member between retracted and deployed positions. Valves may also be used to move the expandable member. The valves may provide fluid communication between the bore and the chamber and may be used to pressurize the chamber to move the expandable member toward the deployed position. The valves may also facilitate releasing pressure in the chamber to move the expandable member toward the retracted position.

In another non-limiting embodiment, a tool is disclosed. The too may include a body with a flow tube and a chamber. A cutter block may be coupled to the body and a valve may selectively allow the chamber and the flow tube to be in communication. Another valve may selectively allow the chamber and an external environment to be in fluid communication. A piston may be coupled to the cutter block and may move in response to pressurization of the chamber. The piston may move from one position in which the cutter block is extended in a radially outward position to another position in which the cutter block is retracted in a radially inward position.

In a further non-limiting embodiment, a method of operating a downhole tool is disclosed. The method may include tripping a drill string into a wellbore. The drill string may be coupled to a downhole tool. A supply fluid may be provided to the downhole tool and the downhole tool may transition into an active state while off-bottom in the wellbore. The transition to the active state may be in response to the supply fluid being at a first pressure. A pressure of the supply fluid may be reduced to a lower, second pressure while the downhole tool is maintained in the active state. Maintaining the downhole tool in the active state may include maintaining a quantity of fluid in the downhole tool at or above the first pressure.

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a perspective view of a downhole tool according to one or more embodiments disclosed herein;

FIG. 2 is a cross-sectional view of a downhole tool with valves in an inactive state according to one or more embodiments disclosed herein;

FIG. 3 is a detailed cross-sectional view of a downhole tool with valves in an inactive state according to one or more embodiments disclosed herein;

FIG. 4 is a cross-sectional view of a downhole tool with valves in an active state according to one or more embodiments disclosed herein;

FIG. 5 is a cross-sectional view of a downhole tool with valves in an active state and which includes a casing shoe according to one or more embodiments disclosed herein;

FIG. 6 is a detailed cross-sectional view of a downhole tool with control valves in an inactive state according to one or more embodiments disclosed herein;

FIG. 7 is a detailed cross-sectional view of a downhole tool with control valves in an active state according to one or more embodiments disclosed herein;

FIG. 8 depicts an illustrative method of operating a downhole tool according to one or more embodiments disclosed herein;

FIG. 9 depicts an illustrative method of activating a downhole tool according to one or more embodiments disclosed herein;

FIG. 10 depicts an illustrative method of deactivating a downhole tool according to one or more embodiments disclosed herein;

FIG. 11 depicts another illustrative method of activating a downhole tool according to one or more embodiments disclosed herein; and

FIG. 12 depicts another illustrative method of deactivating a downhole tool according to one or more embodiments disclosed herein.

DETAILED DESCRIPTION

Some embodiments of the present disclosure relate to expandable tools. Some embodiments described herein generally relate to downhole tools. Some embodiments described herein generally relate to reamers. More particularly, some embodiments herein relate to reamers for increasing the diameter of a wellbore.

FIGS. 1 through 5 illustrate an embodiment of a downhole tool 100, the illustrated embodiment of downhole tool 100 including an expandable tool such as a reamer. Other examples of expandable tools may include, but are not limited to, stabilizers, section mills, expandable anchors, bridge plugs, and the like. With reference to FIG. 1, downhole tool 100 may include a body 102 with one or more expandable members. The expandable members in FIG. 1 may include cutter blocks 104 for use in a reaming operation. In other embodiments, such as where the downhole tool 100 includes other expandable tools, the expandable members may include, but are not limited to, stabilizers blades, section mill blades, anchor slips, sealing members, and the like. FIG. 1 depicts the cutter blocks 104 in a retracted or deactivated position, and the downhole tool 100 in a deactivated or inactive state.

FIGS. 2 and 3 depict cross-sectional views of the downhole tool 100 according to one or more embodiments disclosed herein. The body 102 of the downhole tool 100 may be substantially tubular or cylindrical and may include an axial bore 110 extending at least partially therethrough. The body 102 may be a single component, or the body 102 may be two or more components coupled together.

The cutter blocks 104 may be movably coupled to the body 102 to move between a retracted position, as shown in FIGS. 1 and 2, and an expanded or deployed position, as shown in FIGS. 4 and 5. The number of cutter blocks 104 may vary between embodiments. For instance, there may be between 1 and 20 cutter blocks 104. In at least some embodiments, the number of cutter blocks 104 may be within a range having lower and/or upper limits that include any of 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 12, 15, 20, or values therebetween. For example, there may be between 2 and 5 cutter blocks 104 or between 3 and 8 cutter blocks 104. In a more particular embodiment, the body 102 may have 3 cutter blocks 104. In some embodiments the cutter blocks 104 may be evenly spaced around a longitudinal axis of the downhole tool 100. For example, the cutter blocks 104 may be 120° apart around the longitudinal axis. In other embodiments, the cutter blocks 104 may be spaced more or less than 120°. The cutter blocks 104 may be evenly or unevenly spaced around the longitudinal axis.

The downhole tool 100 may be configured to actuate from a first or inactive state (for example, as shown in FIGS. 1, 2, and 3) to a second or active state (as shown in FIGS. 4 and 5). When the downhole tool 100 is in the inactive state, the cutter blocks 104 may be retracted. In some embodiments, when the cutter blocks 104 are in an inactive or retracted position, the outer surfaces 116 of the cutter blocks 104 may be aligned with, or positioned radially inward from, the outer surface 112 of the body 102. The external surface of the body 102 may have an overall shape of an undergauge stabilizer and the cutter blocks 104 may be contained in the blades of the undergauge stabilizer. In some embodiments, the external surface of the body 102 may be slick, straight, tapered, fluted, or have other configurations, or have portions with different configurations.

When the downhole tool 100 is in the inactive state, the outer surface 116 of each of the cutter blocks 104 may be retracted radially inward of the outer surface of a stabilizer blade. Such state of the downhole tool 100, similar to an undergauge stabilizer, may permit sufficient annular flow passage along the downhole tool 100.

In some embodiments, when the downhole tool 100 is in the inactive state, the outer surface 116 of the cutter blocks 104 may be positioned radially outward from the outer surface 112 of the body 102. When the cutter blocks 104 are positioned radially outward from the body 102 in the retracted position, the cutter blocks 104 may stabilize the body 102 in a wellbore. In at least some embodiments, when the downhole tool 100 is in the inactive state, the cutter blocks 104 may operate as an undergauge stabilizer.

In some embodiments, the cutter blocks 104 may have a plurality of splines, rails, or other features (collectively splines 114) formed on their surfaces. For instance, the splines 114 may be formed on one or more side or lateral surfaces of the cutter blocks 104. The splines 114 may be or include, for example, offset ridges or protrusions that engage corresponding grooves, depressions, or channels (collectively grooves 115) in the body 102. The splines 114 on the cutter blocks 104 and the corresponding grooves 115 on the body 102 may be oriented at an angle with respect to a longitudinal axis through the body 102, for example, longitudinal axis A. In other embodiments, the cutter blocks 104 may include pivoting elements that facilitate transition between active and inactive states. Such pivoting elements may be used in addition to, or instead of, the splines 114 or other features that facilitate translational movement of the cutter blocks 104.

When the downhole tool 100 transitions from the inactive state to the active state, the engagement of the splines 114 on the cutter blocks 104 and the grooves 115 in the body 102 may cause the cutter blocks 104 to move radially outward as the cutter blocks 104 are urged axially along the longitudinal axis A of the body 102. These radially outward and axial movements of the cutter blocks 104 reflect a transition of the downhole tool 100 from an inactive state, in which the cutter blocks 104 are in a retracted position, into an active state, in which the cutter blocks 104 are in a deployed or expanded position. When the downhole tool 100 is in an active state, the outer surfaces 116 of the cutter blocks 104 may be positioned radially outward from the outer surface 112 of the body 102, or further radially outward as compared to the position of the outer surfaces 116 when the cutter blocks 104 are in the retracted position.

The cutter blocks 104 may each have cutting elements 106 coupled thereto. In some embodiments, the cutting elements 106 may be coupled to, and extend outwardly from, the outer surface 116 of the cutter blocks 104. In the same or other embodiments, the cutting elements 106 may be coupled to, and extend outwardly from, lateral or side surfaces of the cutter blocks 104. In at least some embodiments, the cutter blocks 104 may include pockets or recesses in which cutting elements 106 may be positioned and then brazed, welded, or otherwise secured therein. In other embodiments, the cutting elements 106 may be coupled to the cutter block 104 in other manners. For instance, the cutting elements 106 may be applied as hardfacing or crushed carbide, impregnated within the body of the cutter blocks 104, or in other manners. The cutting elements 106 on the cutter blocks 104 may be configured to cut, grind, shear, crush, or otherwise deform or remove a portion of the wall of the wellbore to increase the diameter of the wellbore when the downhole tool 100 is in the active state.

In some embodiments, the cutter blocks 104 may also include a plurality of stabilizer pads 105 and/or gauge protection elements 107 (see FIG. 1) coupled thereto. The stabilizer pads 105 and gauge protection elements 107 may be located on, or coupled to, the outer surface 116 of the cutter blocks 104. In some embodiments, the gauge protection elements 107 may be located within the stabilizer pads 105. For instance, the gauge protection elements 107 may be located in pockets formed in the stabilizer pad 105. In other embodiments, the gauge protection elements 107 may be positioned outside of the stabilizer pads 105, applied as hardfacing or crushed carbide, or excluded. When the cutter blocks 104 include cutting elements 106, stabilizer pads 105, gauge protection elements 107, other structures, or any combination of the foregoing, the downhole tool 100 may function as a cleanout stabilizer. When the cutter blocks 104 include stabilizer pads 105 and/or gauge protection elements 107, but no cutting elements 106, the downhole tool 100 may function as an expandable stabilizer. In some embodiments, an expandable stabilizer may be run in conjunction with a reamer (e.g., in a bottomhole assembly that also includes a reamer). While the illustrated stabilizer pads 105 are shown in FIG. 1 as being located at an intermediate location along the axial length of the cutter blocks 104, in the same or other embodiments, the stabilizer pads 105 may be located at one or more axial ends of the cutter blocks 104.

When the downhole tool 100 is in an inactive state, the cutter blocks 104 may remain retracted and potentially recessed within the body 102, and the outer surface 116 of the cutter blocks 104 may remain radially inward of, or aligned with, the outer surface 112 of the body 102. For example, the cutter blocks 104 may be held in the retracted position by a piston 118 and/or the biasing force of a spring 128 or other bias element. The spring 128 or other bias element may also hold the piston 118 in a particular position (e.g., a position corresponding to the inactive position of the cutter blocks 104).

The downhole tool 100 may be in an inactive state while tripping into a wellbore. While the downhole tool 100 is in the inactive state, an equalization valve 124 may facilitate equalizing of the pressure within a chamber 134 and the pressure of the environment outside the body 102. One example of an environment that is outside or external the body 102 is the annulus of a wellbore. The pressure inside the chamber 134 may therefore be substantially equal to the pressure in the annulus, and in some embodiments there may be no force within the chamber to counteract the force of the spring 128. The equalization valve 124 may be located within a port, opening, or channel (e.g., port 123). The port 123 may, in some embodiments, connect two volumes, such as an annulus and a pressure chamber, in fluid communication.

In some embodiments, the equalization valve 124 may be a check valve. In such embodiments, the equalization valve 124 may be set to have opening and closing pressure setpoints that are low relative to other pressure setpoints within the downhole tool 100, or low relative to other pressure setpoints the equalization valve 124 may use when the equalization valve 124 is adjustable. For example, the equalization valve 124 may be set to open and/or close at a pressure between 5 psi and 100 psi (0.03 MPa and 0.69 MPa). In a more particular embodiment, the equalization valve 124 may be set to open and/or close at a pressure within a range having lower and/or upper limits including any of 5 psi, 10 psi, 15 psi, 20 psi, 30 psi, 45 psi, 60 psi, 80 psi, 100 psi (0.03 MPa, 0.07 MPa, 0.10 MPa, 0.14 MPa, 0.21 MPa, 0.31 MPa, 0.41 MPa, 0.55 MPa, or 0.69 MPa), any value therebetween, or any other pressure that facilitates operation of the downhole tool 100. In other embodiments, the opening and/or closing pressure setpoints may be less than 5 psi or greater than 100 psi (0.03 MPa and 0.69 MPa). In some embodiments, low pressure setpoints allow the equalization valve 124 change or actuate to an open position and facilitate flow from the annulus into the chamber 134, but, when the pressure across the valve from the annulus to the chamber 134 becomes lower than the low pressure setpoint, the equalization valve 124 may change to or actuate to a closed position, thereby restricting flow from the chamber 134 into the annulus.

In addition to the equalization valve 124, and as shown in FIG. 3, the downhole tool 100 may also include a mandrel valve 126 and/or a body valve 122. In some embodiments, the mandrel valve 126 may be located within a port, opening or channel (e.g. port 125) and the body valve 122 may also be located within a port, opening, or channel (e.g., port 121). The port 125 associated with the mandrel valve 126 may, in some embodiments, be formed in a mandrel 108 of the downhole tool 100. In at least some embodiments, the port 125 may extend through a portion of the mandrel 108. For instance, the port 125 may extend radially through the mandrel 108, and between a flow tube 136 or interior bore of the mandrel 108 and the chamber 134 along an outer surface of the mandrel 108. The port 121 associated with the body valve 122 may, in some embodiments, be formed in the body 102 of the downhole tool 100. In at least some embodiments, the port 122 may extend through the body 102. For instance, the port 122 may extend radially through the body 102, and between the chamber 134 along an interior surface of the body 102 and an annulus of a wellbore. In some embodiments, the mandrel valve 126 may be a mechanical check valve. The mandrel valve 126 may allow flow from the flow tube 136 into the chamber 134, but not allow flow from the chamber 134 into the flow tube 136. Thus, when the mandrel valve 126 is open, the flow tube 136 may be in fluid communication with the chamber 134 though the port 122 in the mandrel 108.

In some embodiments, a valve, such as a check valve or the mandrel valve 126, may fluidly couple a supply chamber (e.g., flow tube 136) with a pressure chamber (e.g. chamber 124). In some embodiments, pressurized fluid may flow from the supply chamber, through an open valve (e.g., mandrel valve 126), and into the pressure chamber. In some embodiments, the pressurized fluid within the pressure chamber may act on a piston (e.g., piston 118) or other moveable element.

During drilling operations, drilling fluid or drilling mud may be pumped through the flow tube 136 for any of various uses. For example, the drilling fluid or mud may flow through the flow tube 136 to operate downhole tools, cool cutting elements, clear cuttings away from the face of a cutting tool, carry cuttings up a wellbore, perform other operations, or perform any combination of the foregoing. For such operations, a pressure of the drilling fluid or drilling mud may be less than a pressure at which the mandrel valve 126 is configured to open. For instance, in order to use pressurized mud during drilling operations without opening the mandrel valve 126 and forcing drilling mud into the chamber 134, the mandrel valve 126 may open at or above a mud pressure setpoint higher than a relatively lower pressure of the drilling mud during drilling operations, or higher than a pressure setpoint of the equalization valve 124. An example pressure setpoint at which the mandrel valve 126 opens may, in some embodiments, be an intermediate pressure setpoint between the pressure setpoints of various valves in the downhole tool 100, or between pressures used to perform different functions in the downhole tool 100. For instance, the intermediate pressure setpoint of the mandrel valve 126 may be between 150 psi and 1000 psi (1.0 MPa and 6.9 MPa). More particularly, in some embodiments, the intermediate pressure at which the mandrel valve 126 opens may be within a range having lower and/or upper limits that include any of 150 psi, 300 psi, 400 psi, 500 psi, 600 psi, 800 psi, 1000 psi (1.0 MPa, 2.1 MPa, 2.8 MPa, 3.4 MPa, 4.1 MPa, 5.5 MPa, and 6.9 MPa), or any values therebetween. In other embodiments, the intermediate pressure may be less than 150 psi or greater than 1000 psi (1.0 MPa and 6.9 MPa). In some embodiments, the pressure at which the mandrel valve 126 opens may be lower than the high pressure discussed herein (e.g., a pressure used to open the body valve 122). In other embodiments, the pressure at which the mandrel valve 126 opens may be lower than the pressure used to open a second valve, such as the body valve 122 or the equalization valve 124.

According to at least some embodiments, the body valve 122 may open at a pressure setpoint that is higher relative to the pressure at which the mandrel valve 126 opens. The pressure used to open the body valve 122 may be referred to as a high pressure as it may be higher than the pressure used to open the equalization valve 124 and/or the mandrel valve 126. The high pressure corresponding to the pressure setpoint of the body valve 122 may further be greater than the pressure within the chamber 134 that would counteract the force of the spring 128 and/or which would activate the downhole tool 100. For example, high pressure setpoints of the body valve 122 may, in some embodiments, be between 1000 psi and 3000 psi (6.9 MPa and 20.7 MPa). More particularly, a high pressure used to open the body valve 122 may be within a range that includes lower and/or upper limits including any of 1000 psi, 1250 psi, 1500 psi, 1750 psi, 2000 psi, 2500 psi, 3000 psi (6.9 MPa, 8.6 MPa, 10.3 MPa, 12.1 MPa, 14 MPa, 13.8 MPa, 17.2 MPa, and 20.7 MPa), or any values therebetween. In other embodiments, however, the pressure used to open the body valve 122 may be less than 1000 psi (6.9 MPa) or greater than 3000 psi (20.7 MPa).

FIG. 4 shows the illustrative downhole tool 100 in an active state. In the active state, a moveable element, such as the piston 118, may be moved axially along the longitudinal axis A of the downhole tool 100 toward an upper end portion 130 of the downhole tool 100. When the piston 118 translates or otherwise moves axially along the downhole tool 100, the piston 118 may push a drive ring 120 in the direction of the upper end portion 130 of the downhole tool 100. This drive ring 120, in turn, may push the cutter blocks 104 at least partially in the same direction. For instance, by moving the drive ring 120 axially toward the upper end portion 130 of the downhole tool 100, the cutter blocks 104 may move axially toward the upper end portion 130 of the downhole tool 100. Axial movement of the cutter blocks 104 may also cause the cutter blocks 104 to move radially outward relative to the body 102 of the downhole tool 100. The piston 118 may be coupled indirectly to the cutter block 104 via the drive ring 120. In some embodiments, a piston may be directly coupled to a cutter block or other expandable member without the drive ring 120, or the drive ring 120 may be integral with the piston 118.

In some embodiments, a moveable element may include a flexible or deformable portion, and one portion of the movable element may remain in substantially the same location while another portion of the moveable element moves. For example, a spring-like movable element may include an end that is pinned or fixed in place and remains stationary while another portion moves. A pivoting movable element may include an end that is pinned or rotationally coupled to a part of the downhole tool, while a free end rotates in an arc about the pinned end. Combinations of different types of movable elements may also be used.

As the cutter blocks 104 translate or otherwise move toward the upper end portion 130, the splines 114 of the cutter blocks 104 may cooperate with the grooves 115 in the body 102 to cause the cutter blocks 104 to move radially outward. In an outward or expanded position of the cutter blocks 104, such as that shown in FIG. 4, the outer surface 116 of the cutter blocks 104 and/or the cutting elements 106 may extend beyond the outer surface 112 of the body 102 of the downhole tool 100.

In some embodiments, the piston 118 may translate or move axially along the longitudinal axis A of the downhole tool 100 when the pressure of the fluid within the chamber 134 acts on a surface of the piston 118 facing the interior of the chamber 134 with enough force to overcome the force of the spring 128. The pressure inside the chamber 134 may be increased by allowing drilling fluid or drilling mud into the chamber 134.

As discussed herein, pressurized fluid may enter the chamber 134 from the flow tube 136. In some embodiments, the mandrel valve 126 may open and allow fluid flow into the chamber 134 when the fluid pressure within the flow tube 136 exceeds the opening pressure setpoint of the mandrel valve 126. In some embodiments, the opening pressure setpoint of the mandrel valve 126 may be above the relatively lower opening pressure setpoint of the equalization valve 124. When an operator wishes to activate the downhole tool 100 and extend the cutter blocks 104, the operator may increase the fluid pressure inside the flow tube 136 above the opening pressure setpoint of the mandrel valve 126, but the operator may keep the fluid pressure below the relatively higher opening pressure setpoint of the body valve 122. This may cause drilling fluid or mud to enter the chamber 134. As a result of the fluid pressure remaining below the opening pressure setpoint of the body valve 122, the pressure within the chamber 134 may increase, but the body valve 122 may remain closed and resist flow from the chamber 134 into the annulus.

The characteristics of the spring 128, such as the spring constant and any preloading, may be selected such that the spring 128 holds the cutter blocks 104 in a retracted position and the downhole tool 100 in an inactive state when the fluid pressure within the chamber 134 is below an intermediate pressure, but allows the cutter blocks 104 to transition to an active or expanded position and the downhole tool 100 to transition to an active state when the fluid pressure within the chamber 134 meets or exceeds an intermediate pressure or other pressure setpoint of the mandrel valve 126. When the pressure inside the chamber 134 overcomes the force exerted by the bias spring 128, the piston 118 may begin to translate axially along the longitudinal axis A of the downhole tool 100. Eventually, the pressure within the chamber 134 and the flow tube 136 may begin to equalize. As the pressure in the chamber 134 and the pressure in the flow tube 136 begin to equalize, the differential pressure across the mandrel valve 126 may drop and, in an embodiment where the mandrel valve 126 is a check valve, the mandrel valve 126 may close. When the mandrel valve 126 closes, the pressure within the chamber 124 may hold the piston 118 and cutter blocks 104 in active or expanded positions, thereby maintaining the downhole tool 100 in the active or deployed state. The downhole tool 100 may remain in this state as fluid flows within the flow tube 136 or even if the pressure of the fluid in the flow tube 136 drops or if flow stops entirely.

When the mandrel valve 126 closes, the downhole tool 100 may be in a state where the three valves—namely the mandrel valve 126, the equalization valve 124, and the body valve 122—are closed. The mandrel valve 126 may be closed due to the differential pressure between the flow tube 136 and the inside of the chamber 134 not being great enough to open the mandrel valve 126. The body valve 122 may be closed due to the differential pressure between the chamber 134 and the annulus not being great enough to open the body valve 122. The equalization valve 124, which may be a check valve, may be closed due to the pressure inside the chamber 134 being greater than the pressure in the annulus.

In some embodiments, the process of activating the downhole tool 100 may occur even in the absence of weight-on-bit. An operator may, therefore, activate the downhole tool 100 at an intermediate depth within the wellbore or when the downhole tool 100 is not on the bottom of the wellbore (i.e., is off-bottom). Additionally, in this configuration, the downhole tool 100 may be hydraulically locked in the active or deployed state as the pressurized fluid may be contained in the chamber 134. The pressurized fluid held within the chamber 134 may restrict movement of the cutter blocks 104 or other applicable expandable member or tool, and may maintain the downhole tool 100 in the active state. In the active state, the operator may use the tool to ream the wellbore or stabilize the downhole tool 100 independently of any weight-on-bit or continued drilling fluid flow. In this configuration, the operator may, in some embodiments, therefore lower the pressure of the drilling fluid within the flow tube 136 (e.g., back down to normal operating pressures), stop the flow completely, or switch to using an aerated or other type of drilling fluid. The operator may then continue to operate the downhole tool 100 under these conditions while the downhole tool 100 remains in the active state.

If the mandrel valve 126 were absent or disabled, the port 125 could be open to allow free flow between the flow tube 136 and the chamber 134. Similarly, if the body valve 122 were absent or disabled, the port 121 could allow fluid to flow from the chamber 134 to the annulus. In such configurations, pressure within the chamber 134 could be maintained. For instance, the pressure in the chamber 134 could be maintained where the mandrel valve 126 is removed or disabled by having the operator maintain the pressure within the flow tube 136 at a level high enough to counteract the force of the spring 128. The pressure in the chamber 134 could also be maintained when the body valve 122 is removed or disabled where the combination of the drilling fluid pressure in the annulus and the pressure drop across the body port 121 is high enough that the pressure within the chamber 134 is maintained at a level that overcomes the biasing force of the spring 128.

The pressure in the annulus may be maintained by the head pressure of the fluid in the annulus. In some embodiments, the head pressure in the annulus may be affected by the porosity of the geologic formations through which the downhole tool 100 passes. If the formations are porous, drilling fluid may easily enter the formations and the head pressure in the annulus may be low. When the head pressure in the annulus is low, the fluid that is pumped into the chamber 134 may escape through the body port 121, and pressure within the chamber 134 may not be maintained. These porous locations within a wellbore are called loss zones, or total loss zones. In embodiments in which the downhole tool 100 may remain in the active state even when the flow of drilling fluid is reduced or even stopped (e.g., when a quantity of fluid is contained within the chamber 134 and the downhole tool 100 is hydraulically locked with the cutter blocks 104 in an expanded position), the downhole tool 100 may continue to effectively be operated without the loss of large quantities of drilling fluid to loss zones, or total loss zones.

An operator may wish to return the downhole tool 100 to an inactive state in order to trip the downhole tool 100 out of the wellbore, or to begin reaming in another zone within the wellbore. To return the downhole tool 100 to an inactive state, the biasing force of the spring 128 and any other retraction forces applied directly or indirectly to the cutter blocks 104 should exceed the force applied to the cutter blocks 104 by the piston 134. One method of changing the balance in these forces is to reduce the pressure in the chamber 134. By opening the body valve 122, pressurized fluid within the chamber 134 may flow into the annulus, thereby reducing the pressure within the chamber 134, thereby reducing the force applied by the piston 134.

The body valve 122 may open when the pressure differential across the body valve 122 increases (e.g., exceeds the high opening pressure setpoint as discussed herein). To increase the differential pressure across the body valve 122, the annulus pressure may decrease, the pressure in the chamber 134 may increase, or a combination of the foregoing may occur.

One way to decrease the pressure in the annulus may be to pull the downhole tool 100 up the wellbore. The pressure in the annulus near the downhole tool 100 may be a function of the depth of the downhole tool 100 and may increase with increasing depth and may decrease with decreasing depth. Moving the downhole tool up the wellbore may therefore cause the pressure on the annulus side of the body valve 122 to decrease and, because the valves to the chamber 134 may be closed, the pressure within the chamber 134 may remain constant. The differential pressure across the body valve 122 may therefore increase as the downhole tool 100 is moved toward the surface of the wellbore.

When the differential pressure across the body valve 122 exceeds the opening pressure, the body valve 122 may open and the fluid within the chamber 134 may flow out of the chamber 134 through body valve 122 and into the annulus. When the pressure within the chamber 134 decreases to a point where the force on the piston 134 no longer counteracts the biasing force of the spring 128 on the cutter blocks 104, the spring 128 may cause the cutter blocks 104 to translate axially along the longitudinal axis A of the downhole tool 100 toward the lower end portion 132.

In another embodiment, pressure within the chamber 134 may be increased by increasing the pressure within the flow tube 136. By increasing the pressure of the fluid within the flow tube 136 to a high pressure, the mandrel valve 126 may open, which may cause fluid to enter and pressurize the chamber 134 to a high pressure. Pressurizing the chamber 134 may also cause the body valve 122 to open. At this point, the pressure in the flow tube 136 may be reduced and, if the body valve 122 has a low closing pressure setpoint, the body valve 122 may remain open while fluid drains from the chamber 134 into the annulus. The pressure within the chamber 134 may decrease, allowing the downhole tool 100 to transition to an inactive state. In another embodiment, an ignitor and an explosive material may be used to increase pressure within the chamber 134. The ignitor may be triggered by an electrical signal, in some embodiments. Such signal may be generated or provided by a controller, surface signal, battery, other component, or any combination of the foregoing.

When the downhole tool 100 transitions from an active state to an inactive state, the engagement of the splines 114 on the cutter blocks 104 and the grooves 115 in the body 102 may cause the cutter blocks 104 to move radially inward. This movement of the cutter blocks 104 reflects a transition of the downhole tool 100 from an active state, in which the cutter blocks 104 are in an expanded or deployed position, into an inactive state, in which the cutter blocks 104 are in a retracted or inactive position.

In some embodiments, additional or other mechanisms other than increasing flow in the flow tube 136 or changing the head pressure may be used to transition the downhole tool 100 to an inactive state. For instance, despite the reduction in head pressure by pulling the downhole tool 100 up the wellbore, the differential pressure across the body valve 122, between the chamber 134 and the annulus, may not increase to a level great enough to open the body valve 122. If the operator does not want to increase the pressure in the flow tube 136 to open the body valve 122, the operator may use other methods for transitioning the downhole tool 100 to an inactive state. For example, an operator may apply an additional mechanical force to transition the downhole tool 100 into an inactive state.

An additional mechanical force may act in parallel with, and potentially in a same direction as, the biasing force of the spring 128. In some embodiments, when retrieving the downhole tool 100 from the wellbore, an operator may pull the downhole tool 100 up to engage an un-reamed portion of the formation, a portion of casing, or another object. In FIG. 5, for example, the downhole tool 100 may be pulled up to engage a casing shoe 504. When pulling the downhole tool 100 up against the casing shoe 504, the casing shoe 504 may press down against the cutter blocks 104. The force between the casing shoe 504 and the cutter blocks 104, along with the force applied to the cutter blocks 104 by the spring 128, may push against the piston 118 and toward the lower end portion 132 of the body 102. Such forces may increase the fluid pressure within the chamber 134.

When the pressure within the chamber 134 increases to a level that causes the body valve 122 to open, the fluid within chamber 134 may flow through the body valve 122 and into the annulus, and the cutter blocks 104 and the piston 118 may translate axially along the longitudinal axis A of the body 102 toward the lower end portion 132. As the cutter blocks 104 translate toward the lower end portion 132, the engagement between the splines 114 on the cutter blocks 104 and the grooves 115 in the body 102 may cause the cutter blocks 104 to move radially inward and into an inactive state.

When a mechanical force is applied, the mechanical force may be applied while the downhole tool 100 is rotating or not rotating. For instance, during a reaming operation, the downhole tool 100 may rotate and move axially within the wellbore. To retract the cutter blocks 104, the rotation may slow or stop and the downhole tool 100 may be pulled up to apply an axially force that increases the fluid pressure within the chamber 134. In other embodiments, the downhole tool 100 may continue to rotate while being pulled up to increase the fluid pressure within the chamber 134.

Although the present disclosure discuses tools in the context of illustrative reamer embodiments, this disclosure is also applicable to embodiments that include other types of reamers or other tools, including no-flow locked reamers as discussed herein. Embodiments of the present disclosure, including activation systems, may be used in other tools, such as, for example, expandable anchors, bridge plugs, expandable stabilizers, section mills, casing jacks, inflatable packers, casing cutters, and pipe cutters.

In some embodiments, a tool (e.g., downhole tool 100 of FIGS. 1 through 5) may include control valves to facilitate actuating the tool and/or transitioning between active and inactive states. For example, in the embodiment shown in FIGS. 6 and 7, a tool may be a downhole tool 600 and may include a body valve 622 located within a port 621, and a mandrel valve 626 located within a port 625. The body valve 622 and the port 621 may connect a chamber 634 with an annulus or other chamber or area outside a body 602, and the mandrel valve 626 and the port 625 may connect a flow tube 636 with the chamber 634 through a mandrel 608. The body valve 622 and the mandrel valve 626 may be on/off flow valves that facilitate the actuation of the downhole tool 600 between an active and an inactive state. In some embodiments one or more of the body valve 622 or the mandrel valve 626 may be adjustable check valves.

In simple terms, a control valve is a type of valve that changes between open and closed positions in response to a signal or signals. A signal may include electromagnetic, electrical, mechanical, or any other type of signal. For example, an electrically actuated control valve might open and close based on the polarity of the electric voltage applied to the valve's electric actuator. Another type of control valve may be an adjustable check valve, which may be opened in any of various different ways. In some embodiments a controller may adjust the opening pressure setpoint of an adjustable check valve. In some embodiments signals may be sent from the surface down to the adjustable check valve to adjust the opening pressure setpoint or the adjustable check valve may be adjusted at the surface prior to being tripped into the wellbore. An adjustable check valve may open when a controller applies electric current to the adjustable check valve's solenoid. In some embodiments, even when electric current is not applied to the valve's solenoid, the adjustable check valve may open when the differential pressure across the adjustable check valve is greater than the opening set pressure of the adjustable check valve, thus causing the adjustable check valve to act like a mechanical check valve.

A transition between active and inactive states of the downhole tool 600 will now be described with reference to FIGS. 6 and 7. On the trip into the wellbore, the downhole tool 600 may be in an inactive state with the cutter blocks 604 retracted such that the cutting elements 606 and the outer surface 616 are radially inward of, or flush with, the outer surface 612 of the body 602. During the trip into the wellbore, the body valve 622 may be open and the mandrel valve 626 may be closed and set to an intermediate opening pressure, for example, 400 psi (2.8 MPa). In this configuration, the pressure within the piston chamber 634 may be balanced or equalized with the pressure in the annulus by reverse free flow of fluid between the annulus and the chamber 634 through the open body valve 622.

Downhole operations (e.g., drilling the pilot hole, milling casing, etc.), may proceed with the cutter blocks 604 in the retraced position. The downhole tool 600 may thus be used for downhole operations without activating the downhole tool 600. In some embodiments, the downhole operations may occur while the drilling fluid pressure within the flow tube 636 does not exceed the mandrel valve opening pressure setpoint.

To transition to an active state, an operator may send a signal or signals from the surface down to a controller or controllers contained within the downhole tool 600 or otherwise located in the wellbore. This process is sometimes referred to as downlinking. For example, the downhole tool 600 may include a controller 642. An operator may downlink with a downhole tool 600 using any of a number of methods, including, for example, rotation, shock, pressure pulses, wired drill pipe, and fluid flow. In a more particular example, the operator may vary the rotation of the drill string, send shocks down the drill string, create pulses pressure pulses transmitted through the annulus of the wellbore or through the drill string, change the drilling fluid flow rate to send instructions to a downhole controller, send electronic communications through wired drill pipe, or the like. The downhole controller may include sensors for measuring or detecting these changes, as well as instructions for interpreting and acting on the signals, for example, by changing the state of a control valve.

A power supply, such as a battery 638, may provide power for operating the controller 642 and/or various valves 622, 626. In some embodiments, the battery 638 may connect to the controller 642 through power conductors 640. The controller 642 may be electrically connected to the valves 622, 626 through conductors 624, 626.

In some embodiments, for example the embodiment of FIGS. 6 and 7, an operator may downlink a command to the downhole controller 640 that causes the controller 640 to set the body valve 622 to a closed position and/or to set the body valve 622 to have a high opening pressure setpoint, for example 1,500 psi (10.3 MPa). The same or a similar command may be used to cause the mandrel valve 626 to change to an open position or to set the mandrel valve 626 to an intermediate opening pressure setpoint. In this configuration, drilling fluid may flow from the flow tube 636, located within the bore 610 of the body 602, through the mandrel valve 626, and into the chamber 634. The fluid may be held within the chamber by the closed body valve 622. As the chamber 634 fills with fluid and becomes pressurized, the force on the piston 618 may increase. When the force exerted by the fluid in the chamber 634 on the piston 618 overcomes the biasing force of spring 628, the piston 618 may translate axially along the longitudinal axis B of the downhole tool 600 in the direction of the upper end portion 630 of the downhole tool 600. The translation of the piston 618 may cause the cutter blocks 604 to also translate toward the upper end portion 630 of the downhole tool 600. As the cutter blocks 604 translate, splines, rails or other features (see splines 114 of FIG. 1) of the cutter blocks 604 and grooves or channels (see grooves 115 of FIG. 1) in the body 602 may cause the cutter blocks 604 to move to a radially outward position, such as that shown in FIG. 7. In a radially outward position, the outer surface 616 of the cutter blocks 604 and the cutting elements 606 may extend further radially outward than when in a retracted position as shown in FIG. 6, which may also be radially outward beyond the outer surface 612 of the body 602 of the downhole tool 600.

When the chamber 634 is pressurized and the downhole tool 600 is in an active state, a signal or signals sent from the controller 642 (e.g., in response to downlinking commands from the surface) may cause the mandrel valve 626 to close and/or may set the opening pressure setpoint of the mandrel valve 626 to a high level, for example, 1500 psi (10.3 MPa), which may be above the pressure of the fluid within the mandrel 608. In this configuration, the mandrel valve 626 may be closed while a quantity of fluid is contained in the chamber 634 and at a pressure sufficient to maintain the downhole tool 600 in the active state. As the quantity of fluid in the chamber 634 remains pressurized, the downhole tool 600 may be hydraulically locked in an active or deployed state and the cutter blocks 604 may remain extended without the need for additional drilling fluid flow into or through the chamber 634 or the mandrel 608. Indeed, the downhole tool 600 may remain in an active state even when the flow tube 636 and the annulus lose pressure.

In some embodiments, the operator may return the downhole tool 600 to an inactive state, for example, to trip the downhole tool 600 out of the wellbore, or to move the downhole tool 600 within the wellbore. To return the downhole tool 600 to an inactive state, the controller 642 may send a send a signal or signals to the body valve 622 to cause the body valve 622 to open and/or to change the opening pressure setpoint of the body valve 622.

Opening the body valve 622 may break the seal on the chamber 634 and allow fluid to flow out of the chamber 634 and into the annulus of the wellbore. When the seal on the chamber 634 is broken or otherwise released, the biasing force of the spring 628 may push against the cutter blocks 604 and the piston 618 in an axial direction toward the lower end portion 632 of the body 602. This may push the drilling fluid held within the chamber 634 out through the body valve 622 and into the annulus. The biasing force of the spring 628 may also cause the cutter blocks 604 and the piston 618 to translate axially toward the lower end portion 632 of the body 602.

The axial translation of the cutter blocks 604 combined with the engagement of the splines, rails, or other features on the cutter blocks 604 with the grooves or channels in the body 602, may cause the cutter blocks 604 to move radially inward and the downhole tool 600 to transition into an inactive state where the cutting elements 606 and the outer surface 616 of the cutter blocks 604 retract such that they are in a position radially inward of, or flush with, the outer surface 612 of the body 602. In some embodiments, an operator may leave the body valve 622 open during additional drilling operations or while the downhole tool 600 makes the trip out of the wellbore.

In the embodiment shown in FIGS. 1 through 7, the operator may transition a downhole tool 100, 600 between active and inactive states by operating the downhole tool 100, 600 and its valves as described herein. Such operation may save time because the state of the downhole tool may transition between active and inactive states multiple times without tripping the downhole tool out of the wellbore. Such operation may also save drilling fluid because the downhole tool can be maintained, or locked (e.g., hydraulically locked), in an active state without constant drilling fluid flow and pressure, also called a “no-flow” condition. This may potentially be used when the downhole tool 100, 600 is operating in a loss zone or a total loss zone. The downhole tool 100, 600 may also be operated without weight-on-bit or with the bit off-bottom; therefore, an operator may activate and deactivate the downhole tool 100, 600 while at any position within the wellbore, and use the downhole tool to underream and back ream within a wellbore.

Although the embodiments shown in the figures depict two or three valves for managing the flow into and out of a chamber, in some embodiments, more or fewer valves may be used to manage the flow into and out of a chamber. In some embodiments, for instance, a downhole tool may include a single valve to facilitate transitioning the downhole tool between active and inactive states. For example, a downhole tool may include a single mandrel valve that allows fluid into a chamber from a flow tube to activate the downhole tool and allows fluid from the chamber to the flow tube to deactivate the valve. In other embodiments, multiple mandrel valves may be used to control fluid flow into an annular chamber.

FIG. 8 depicts an illustrative method 800 of operating a downhole tool according to one or more embodiments disclosed herein. At block 802 the method 800 includes tripping a drill string into a wellbore. A drill string may include drill pipe, a bottomhole assembly, or any other tools used in a wellbore drilling or other downhole process. The bottomhole assembly may include a downhole tool, for example, a downhole tool 100 (FIG. 1) or 600 (FIG. 6). In some embodiments, the trip-in process may include inserting the drill string into the wellbore and through the existing casing and/or openhole portions of the wellbore toward the bottom of an existing wellbore.

At block 804 the wellbore is drilled. For example, once the drill string reaches the bottom of the wellbore or the end of a lateral or deviated borehole, the operator may begin drilling and extending the wellbore's depth or length. In some embodiments, for example when a wellbore has collapsed, the operator may begin drilling the wellbore before reaching the bottom of the wellbore.

At block 806 the downhole tool is activated and at block 808 the downhole tool is operated. In some embodiments, the operator may activate and operate the downhole tool (e.g., to enlarge the wellbore) while drilling. This process is called hole enlargement while drilling. In order to enlarge the wellbore while drilling, the operator may activate the downhole tool, as shown by block 806 and operate the downhole tool, as indicated by block 808. Other operations may include, but are not limited to, underreaming, back reaming, section milling, sealing the wellbore, pulling casing, cutting casing, fishing operations, and the like. In other embodiments, the downhole tool may be activated and/or operated for operations performed independently of drilling operations.

The downhole tool may also be deactivated, as shown by block 810. For example, in some embodiments, the operator may put a downhole tool into an inactive state in order to pull the drill string up through an openhole or cased section of the wellbore, and through a smaller internal diameter than the downhole tool will fit through when the downhole tool is in an active state. In some embodiments, after deactivating the downhole tool, the operator may continue to drill the wellbore, as shown by block 812.

In some embodiments, the downhole tool may be activated, operated, and deactivated multiple times during a single trip in the wellbore. The operator may also conduct multiple drilling operations during a single trip. Therefore, the method 800 may be carried out in an order other than the order shown in FIG. 8, and one or more actions may occur multiple times during a single trip. In the same or other embodiments, less than each action shown in method 800 may be carried out during a trip.

At block 814 the method 800 includes tripping the drill string out of the wellbore. In some embodiments, the entire drill string may be removed from the wellbore during the trip out. In other embodiments, however, portions of the drill string that were carried into the wellbore during the trip in may be left in the wellbore during the trip out.

The process of drilling a wellbore may include using method 800 (or portions thereof) multiple times. For example, if a downhole tool breaks or fails during one trip, the operator may pull the drill string out of the wellbore to replace or fix the downhole tool, or to fish for the downhole tool. In some embodiments, the operator may reconfigure the downhole tool to complete different sections of the wellbore, for example, the shallow or upper portions of the wellbore may have a larger diameter than the lower or deeper portions of the wellbore. In such embodiments, the operator may use a set of reamers and drill bits sized for drilling and reaming one portion of the wellbore and another set of reamers and drill bits sized for drilling and reaming another portion of the wellbore.

FIG. 9 depicts an embodiment of a method 900 of activating a tool, and may include a method of activating a downhole tool. At block 902 the pressure of a supply fluid is increased. In some embodiments, a flow tube may contain or transport the supply fluid, for example, flow tube 136, as shown in FIG. 2. In some embodiments, the operator may increase the pressure in the flow tube by pumping drilling fluid into the wellbore at a greater flow rate or otherwise causing a drilling system to increase the pressure of the drilling fluid.

At block 904 pressure is increased across a first valve. In some embodiments, increasing the pressure of a supply fluid may cause an increase in pressure across a first valve. In some embodiments, the first valve may be a check valve, and more particularly, a check valve located in a mandrel or other flow tube and configured such that when the valve is open, the valve connects the flow tube in fluid communication with a chamber.

At block 906 the first valve is opened (e.g., in response to an increase in pressure of the supply fluid) and at block 908 a chamber fills with pressurized fluid. In some embodiments, opening the first valve may put the flow tube in fluid communication with the chamber and cause the chamber to fill with pressurized fluid. The pressurized fluid may include drilling fluid, hydraulic fluid, or other fluid that facilitates the opening of the first valve and/or filling the chamber with pressurized fluid.

At block 910 a piston or other movable element or drive mechanism may be moved. In some embodiments, a spring may apply a biasing force directly or indirectly onto the piston to bias the piston toward an inactive position. When the chamber is unpressurized or contains fluid at a low pressure, the spring may maintain the piston in the inactive position, but when the force of the pressurized fluid on the piston exceeds the biasing force of the spring, the piston may move.

In some embodiments, the piston may move by, for instance, translating axially along the longitudinal axis of the downhole tool. In some embodiments, in addition to translating longitudinally, the piston may also rotate. The piston may also translate or otherwise move in other directions that facilitate the transition of a downhole tool between an inactive state and an active state, and vice versa.

At block 912, the method 900 of activating a tool may include transitioning the tool into an active position. In some embodiments, two opposing forces may act on the tool. For example, as shown in FIGS. 1 through 4, a spring 128 may act on one end of the cutter blocks 104 and push the cutter blocks 104 toward the lower end of the body 102 of the downhole tool 100, while the piston 118 may act on another end of the cutter blocks 104 and push the cutter blocks 104 toward the upper end of the body 102. In the inactive position (see FIG. 2), the biasing force of the spring 128 on the cutter blocks 104 may exceed the force of the piston 118 on the cutter block 104. In the active position (see FIG. 4), the force of the piston 118 on the cutter blocks 104 may exceed the biasing force of the spring 128 on the cutter blocks 104. At block 912, some embodiments may include transitioning a downhole tool into an active state in response to the force of the fluid pressure on the piston exceeding the force applied to the downhole tool, such as to the cutter blocks by, for example, a spring.

Transitioning the tool into an active state at block 912 may also include causing cutter blocks or other expandable members to extend from a retracted, radially inward, or inactive position, to an expanded, radially outward, or active position. In the radially outward position the outer surface and/or the cutting elements of the cutter blocks may extend radially beyond the outer surface of the body of the downhole tool.

At block 914 the first valve may close. In some embodiments, the first valve may close after transitioning the downhole tool into an active state at block 912. In some embodiments, as the chamber fills with pressurized fluid (block 908) the pressure within the chamber may increase. As the pressure within the chamber increases, the differential pressure across the first valve chamber may decrease. In an embodiment wherein the first valve is a check valve, the decrease in the differential pressure across the first valve may reduce to a point below the closing pressure of the check valve. When this occurs, the first valve may close and the chamber may be sealed. The sealed chamber may remain pressurized, holding the downhole in an active state. Block 914 may also include, for example, reducing the flow rate of fluid into the tool, below a threshold flow rate, or stopping the flow of fluid into the tool. In some embodiments, such as where the tool is a downhole tool, block 914 may include reducing the flow rate of drilling fluid into a wellbore or the downhole tool below a threshold flow rate. In some embodiments, the threshold flow rate may be less than 1 L/min, 5 L/min, 10 L/min, 15 L/min, 20 L/min, 30 L/min, 60 L/min, 100 L/min, or any value therebetween. In still other embodiments, the threshold flow rate may be greater than 100 L/min. The tool (e.g., a downhole tool) may remain in an active position until a valve, for example, a second valve, opens and releases the pressurized fluid contained within the chamber.

FIG. 10 shows an embodiment of a method 1000 for deactivating a tool (e.g., a downhole tool). Deactivating a tool may include transitioning a downhole tool from an active state to an inactive state. The method 1000 for deactivating a tool may include increasing the pressure of a supply fluid, as shown by block 1002. In some embodiments, a flow tube may contain or transport the supply fluid; for example, flow tube 136, as shown in FIG. 2.

At block 1004 pressure may be increased across a first valve. In some embodiments, increasing the pressure of a supply fluid may cause an increasing pressure across a first valve. In some embodiments, the first valve may be a check valve, or more particularly, a check valve located in a mandrel or other flow tube and configured such that when the valve is open, the first valve connects the flow tube in fluid communication with a chamber.

The method 1000 of deactivating a tool may include causing the first valve to open, as depicted by block 1006. Opening the first valve may put a flow tube of a downhole tool in fluid communication with a chamber, thereby pressurizing the chamber with supply fluid. In some embodiments, the first valve may have an intermediate opening pressure setpoint. The first valve may therefore open when the differential pressure across the first valve exceeds the intermediate opening pressure setpoint.

In some embodiments, the second valve may have an opening pressure setpoint higher than the intermediate opening pressure setpoint, and may therefore be referred to as having a high opening pressure setpoint. In such embodiments, the fluid in the chamber may reach a pressure such that the differential pressure across the second valve, for example, between a chamber and an annulus, exceeds the high opening pressure setpoint of the second valve. Thus, at block 1008 the chamber may be pressurized with a supply fluid, and at block 1010 the pressure across the second valve may be increased. Increasing the pressure across the second valve in block 1010 may be performed by, for instance, by pumping drilling fluid into a wellbore and, in particular, into a flow tube of a downhole tool, which may cause the pressure within the flow tube to increase. Increasing the pressure in the flow tube may cause the first valve to open and the fluid to enter and increase the pressure within the chamber. A relatively high pressure in the chamber may cause the differential pressure across the second valve to increase until the differential pressure exceeds the opening pressure setpoint of the second valve, causing the second valve to open. As another example, the pressure across the second valve in block 1010 may be increased by moving a downhole tool toward the surface of a wellbore. The pressure within the annulus may decrease with decreasing depth in the wellbore; therefore, moving the downhole tool toward the surface may decrease the pressure on the outside of the second valve and increase the differential pressure across the second valve. In still another example, increasing pressure across a second valve at block 1010 may include applying a mechanical force. For instance, a mechanical force may be applied to a cutter block or expandable member of a downhole tool. The mechanical force may oppose a force applied by a piston or other movable member, which may increase pressure in the chamber and increase the differential pressure across the second valve.

At block 1012 the second valve opens and at block 1014 pressurized fluid is released from the chamber. In some embodiments, when the second valve opens it connects the chamber in fluid communication with an external environment. For a downhole tool, the external environment may be an annulus within a wellbore. When the chamber and the external environment are in fluid communication with each other, the fluid within the chamber may flow out into the external environment, thereby causing the pressure within the chamber to decrease.

In some embodiments, after the second valve opens, the pressure of the supply fluid in the downhole tool may be reduced. Reducing the pressure of the supply fluid may cause the differential pressure across the first valve to drop below the closing pressure setpoint and the first valve to close. In other embodiments, the pressure of the supply fluid in the downhole tool may be reduced prior to opening the second valve.

In some embodiments, one or more of the valves of a tool may have a delayed closing setpoint. Delayed closing means that the valve closes at a lower pressure than the pressure which opens the valve. For example, the second valve may open with a high pressure differential or opening setpoint, for example, 1,500 psi (10.3 MPa), but may not close until a lower pressure differential or closing setpoint exists, for example, 10 or 20 psi (0.07 MPA or 0.14 MPa). The lower closing pressure setpoint may allow the second valve to remain open while the supply fluid drains from the chamber into the external environment and the piston moves to an inactive position.

Using a valve with a high opening pressure setpoint and a low closing pressure setpoint allows the valve to remain closed during an initial activation period, for example, as described above with reference to FIG. 8, but then open to facilitate depressurization and transition to an inactive state. For example, at block 1016 of FIG. 10, the piston moves, and at block 1018 a tool, such as an expandable downhole tool, may move into an inactive state. In some embodiments, the expandable downhole tool may be a reamer, and transitioning the reamer into an inactive state may include retracting cutter blocks.

Moving the piston may include translating the piston axially along the longitudinal axis of a tool. In some embodiments, as the pressure within the chamber decreases, the biasing force of the spring of a downhole tool may overcome the force of the fluid on the piston. When this occurs, the biasing force of the spring may cause the downhole tool to transition from an active state to an inactive state. For example, moving the piston may cause cutter blocks to retract from a radially outward, active position to a radially inward, inactive position. In the radially inward position, the outer surface and the cutting elements of the cutter blocks may be retracted to a position that is radially inward of, or about flush with, the radially outer surface of the body of the downhole tool.

At block 1020 the second valve may be closed. The second valve may close when a pressure differential across the second valve decreases, when an actuation signal is received, or in any other suitable manner. The second valve may also close for a number of reasons, including to restrict or even prevent fluid from flowing into the chamber from an external environment such as an annulus of a wellbore.

FIG. 11 depicts an embodiment of a method 1100 of activating a tool according to one or more embodiments disclosed herein. The tool activated in the method 1100 may include a downhole tool or any other suitable tool. At block 1102 a first valve is opened. In some embodiments, the first valve is a mandrel valve that, when opened, connects a flow tube in fluid communication with a chamber.

In some embodiments, the first valve may be an electrically actuated valve or another type of control valve. Block 1102 may include sending a signal to a controller, and in the case of a downhole tool, the signal may be sent from the surface down the wellbore. The controller may receive one or more signals or instructions that can be processed to cause the first valve to open. The controller may direct the first valve to open by applying voltage to the valve such that a solenoid of the valve is activated and the valve is opened. In some embodiments, the voltage applied to the valve by the controller may cause a motor to turn and open the valve. In some embodiments, opening the first valve at block 1102 may include the controller adjusting the first valve to set a configurable opening pressure setpoint. The first valve may then open when the pressure differential across the valve, or a pressure within the tool, reaches or exceeds the opening pressure setpoint.

At block 1104 a chamber may fill with pressurized fluid. The chamber may fill with pressurized fluid that flows through the first valve opened in block 1102. Block 1104 may include pressurizing a supply fluid, for example, by pumping fluid into a tool (e.g., pumping drilling fluid into a downhole tool in a wellbore) at a high flow rate. The high flow rate may be above the opening pressure setpoint of the first valve. A tool may also be operated in other manners to cause a chamber to fill with pressurized fluid. In some embodiments, filling the chamber with pressurized fluid at block 1104 may causes a piston to move, as shown in block 1106.

In some embodiments, a spring may hold the piston in an inactive position when the chamber is unpressurized or contains fluid at a low pressure. The piston may move when the pressure within the chamber acts on the piston with enough force to overcome the biasing force of the spring.

In some embodiments, the piston may translate axially along the longitudinal axis of the tool, or otherwise move within the tool. In some embodiments, in addition to, or instead of, translating longitudinally, the piston may rotate. The piston may also translate or otherwise move in other directions that facilitate the transition of a tool between an inactive state and active state.

At block 1108 the downhole tool may transition to an active state. Moving the piston may include transitioning a tool to an active state. Moving the piston may include applying a force to an expandable member, such as the cutter blocks of a reamer or other downhole tool, which may cause the cutter blocks to move from an inactive position to an active position. For example, moving the piston may cause the cutter blocks to extend from a radially inward, inactive position to a radially outward, active position. In the radially outward, active position, the outer surface and the cutting elements of the cutter blocks may extend beyond the radially outer surface of the body of the tool.

At block 1110 the first valve may be closed. In some embodiments, after moving a tool into an active position the first valve may close. Closing the first valve may include reducing a pressure of the supply fluid and/or sending a signal to the first valve (e.g., from the surface of a wellbore and down the wellbore to a controller). The controller may receive one or more signals and close the first valve (e.g., by issuing a close command or instruction). The controller may close the first valve by removing a voltage to the valve such that the valve's solenoid is deactivated and the valve is closed. In some embodiments, the controller may apply a voltage to the valve which may cause a motor to turn and close the valve. When the first valve closes, the chamber may be sealed. A sealed chamber may remain pressurized, holding the tool in an active state even in the absence of continued fluid flow. In other embodiments, the first valve may have a configurable opening or closing pressure setpoint. In such an embodiment, the controller may adjust the opening or closing pressure setpoint of the first valve. By increasing the closing pressure setpoint to be above the pressure of the supply fluid, the first valve may then also close as the pressure of the supply fluid will be below the minimum pressure at which the first valve remains open (i.e., the closing pressure setpoint). In some embodiments, by increasing the opening pressure setpoint of the first valve to be above the pressure of the supply fluid, the first valve may further be closed as the pressure of the supply fluid may be below the minimum pressure at which the first valve will open (i.e., the opening pressure setpoint).

According to some embodiments, closing the first valve may not include sending an additional signal (e.g., from the surface to a controller of a downhole tool). For example, the signal sent as described with respect to block 1102 may include instructions or commands that tell a controller the conditions under which to open and the conditions under which to close the first valve. The first valve may, therefore, be closed without receiving additional signals from an external or other source, or the tool may be configured to close the valve when a certain pressure is reached within the chamber or after a certain period of time. The tool may remain in an active state until a valve, for example, a second valve, opens and releases the pressurized fluid contained within the chamber.

FIG. 12 depicts an embodiment of a method 1200 of deactivating a tool. The tool deactivated in the method 1200 may be a downhole tool or other tool. At block 1202 a second valve is opened. Opening the second valve at block 1202 may connect a chamber in fluid communication with an external environment, such as an annulus of a wellbore when the tool is a downhole tool. In some embodiments, the second valve may be an electrically actuated valve or other type of control valve. Opening the second valve may include sending a signal to a controller (e.g., from the surface down the wellbore). The signal may be a pressure signal, rotational signal, electrical signal, an RFID or tracer signal, or the like, and the controller may receive one or more signals and open the second valve. The controller may open the second valve by applying voltage to the valve (or causing the voltage to be applied) such that the second valve's solenoid is activated and the second valve is opened. In some embodiments, the voltage applied to the second valve by the controller may cause a motor to turn and open the second valve. In other embodiments, the second valve may have a configurable opening or closing pressure setpoint that may be set by the controller in response to a sent signal.

In still other embodiments, opening the second valve at block 1202 may include using a mechanical force to increase the pressure in the chamber above an opening pressure setpoint of the second valve. For instance, a downhole tool may include a piston that moves in response to forces applied by pressurized fluid in a chamber. A mechanical force may be applied to oppose the opening force of the piston (e.g., by applying a force to a cutter block or other expandable member of a downhole tool), which may increase the pressure within the chamber. The increased pressure may exceed the opening pressure setpoint of the second valve and cause the second valve to open at block 1202.

At block 1204 the chamber may release pressurized fluid. The pressurized fluid may be released to any location. In some embodiments, when the chamber is in fluid communication with a wellbore annulus or some other external environment, the fluid within the chamber may flow out into the external environment, causing the pressure within the chamber to decrease.

At block 1208 the tool may transition into an inactive state. Block 1208 may include translating a piston axially along a longitudinal axis of the tool. In some embodiments, as the pressure within the chamber decreases, the biasing force of a spring may overcome the force of the fluid on the piston. When this occurs, the biasing force of the spring may cause expandable members, such as the cutter blocks of a reamer, to move from an active position to an inactive position. For example, moving the piston as shown by block 1206 may cause cutter blocks to retract from a radially outward, active position to a radially inward, inactive position. In the radially inward position the outer surface and the cutting elements of the cutter blocks may retract to a position that is radially inward of, or about flush with, the radially outer surface of the body of the downhole tool.

In some embodiments, at block 1210 the second valve may close. The second valve may close in response to any number of stimuli and for a number of reasons. The second valve may close to restrict or even prevent fluid from flowing into the chamber from an external environment. The second valve may close in response to a signal sent to a controller within or coupled to the tool, or in response to a decrease in differential pressure across the second valve.

In some embodiments, a method of deactivating a tool may include opening a first valve. For example, if opening the first valve connects a chamber in fluid communication with a flow tube or other supply chamber, then, if the pressure within the flow tube is lower than the pressure within the chamber, pressurized fluid within the chamber may flow into the flow tube. This may cause the pressure in the chamber to decrease and the downhole tool to transition into an inactive state.

A few example embodiments have been described in detail herein; however, those skilled in the art will readily appreciate in view of the present disclosure that many modifications are possible in the example embodiments without materially departing from the scope of the present disclosure or the appended claims. Accordingly, such modifications are intended to be included within the scope of this disclosure. Likewise, while the disclosure herein contains many specifics, these specifics should not be construed as limiting the scope of the disclosure or of any of the appended claims, but merely as providing information pertinent to one or more specific embodiments that may fall within the scope of the disclosure and the appended claims. Any described features from the various embodiments disclosed may be employed in combination. In addition, other embodiments of the present disclosure may also be devised which lie within the scopes of the disclosure and the appended claims. Additions, deletions and modifications to the embodiments that fall within the meaning and scopes of the claims are to be embraced by the claims.

In the description herein, various relational terms are provided to facilitate an understanding of various aspects of some embodiments of the present disclosure. Relational terms such as “bottom,” “below,” “top,” “above,” “back,” “front,” “left,” “right,” “rear,” “forward,” “up,” “down,” “horizontal,” “vertical,” “clockwise,” “counterclockwise,” “upper,” “lower,” “uphole,” “downhole,” and the like, may be used to describe various components, including their operation and/or illustrated position relative to one or more other components. Relational terms do not indicate a particular orientation for each embodiment within the scope of the description or claims. For example, a component of a bottomhole assembly or downhole tool that is described as “below” another component may be further from the surface while within a vertical wellbore, but may have a different orientation during assembly, when removed from the wellbore, or in a deviated borehole. Accordingly, relational descriptions are intended solely for convenience in facilitating reference to various components, but such relational aspects may be reversed, flipped, rotated, moved in space, placed in a diagonal orientation or position, placed horizontally or vertically, or similarly modified. Certain descriptions or designations of components as “first,” “second,” “third,” and the like may also be used to differentiate between identical components or between components which are similar in use, structure, or operation. Such language is not intended to limit a component to a singular designation. As such, a component referenced in the specification as the “first” component may be the same or different than a component that is referenced in the claims as a “first” component.

Furthermore, while the description or claims may refer to “an additional” or “other” element, feature, aspect, component, or the like, it does not preclude there being a single element, or more than one, of the additional or other element. Where the claims or description refer to “a” or “an” element, such reference is not be construed that there is just one of that element, but is instead to be inclusive of other components and understood as “at least one” of the element. It is to be understood that where the specification states that a component, feature, structure, function, or characteristic “may,” “might,” “can,” or “could” be included, that particular component, feature, structure, or characteristic is provided in some embodiments, but is optional for other embodiments of the present disclosure. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with,” or “in connection with via one or more intermediate elements or members.” Components that are “integral” or “integrally” formed include components made from the same piece of material, or sets of materials, such as by being commonly molded or cast from the same material, or machined from the same one or more pieces of material stock. Components that are “integral” should also be understood to be “coupled” together.

A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function.

While embodiments disclosed herein may be used in oil, gas, or other hydrocarbon exploration or production environments, such environments are merely illustrative. Systems, tools, assemblies, methods, reamers, downhole tools, actuation systems, valves, and other components of the present disclosure, or which would be appreciated in view of the disclosure herein, may be used in other applications and environments. In other embodiments, systems, tools, and methods of the present disclosure or which would be appreciated in view of the disclosure herein, may be used outside of a downhole environment, including within automotive, aquatic, aerospace, hydroelectric, manufacturing, other environments, or even in other downhole environments. The terms “well,” “wellbore,” “borehole,” “downhole”, and the like are therefore also not intended to limit embodiments of the present disclosure to a particular industry or environment. A wellbore or borehole may, for instance, be used for oil and gas production and exploration, water production and exploration, mining, utility line placement, or myriad other applications.

Certain embodiments and features may have been described using a set of numerical values that may provide lower and/or upper limits It should be appreciated that ranges including the combination of any two values are contemplated unless otherwise indicated (e.g., between 200 psi and 500 psi), as are ranges including a single value (e.g., up to 500 psi, or at least 200 psi), or that any particular value may be used. Numbers, percentages, ratios, measurements, or other values stated herein are intended to include the stated value as well as other values that are about or approximately the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least experimental error and variations that would be expected by a person having ordinary skill in the art, as well as the variation to be expected in a suitable manufacturing or production process. A value that is about or approximately the stated value and is therefore encompassed by the stated value may further include values that are within 10%, within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

The Abstract included with this disclosure is provided to allow the reader to quickly ascertain the general nature of some embodiments of the present disclosure. The Abstract is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

1. A downhole tool for reaming a wellbore, comprising:

a body having an inner surface that defines a bore, the body further having a chamber defined therein;

an expandable member movably coupled to the body;

a moveable element movably coupled to the body and configured to move to cause the expandable member to move between a retracted position and a deployed position; and

at least one valve providing fluid communication between the bore and the chamber, the at least one valve being configured to facilitate pressurizing the chamber to move the expandable member toward the deployed position and to facilitate releasing pressure in the chamber to allow the expandable member to move toward the retracted position.

2. The downhole tool of claim 1, the at least one valve including a check valve configured to facilitate fluid flow:

from the bore to the chamber and to restrict flow from the chamber to the bore; or

from the chamber to an external environment and to restrict flow from the external environment to the chamber.

3. The downhole tool of claim 1, further comprising:

a bias element configured to apply a force to the expandable member to move the expandable member toward the retracted position.

4. The downhole tool of claim 1, the moveable element being located at least partially within the chamber and configured to apply a force to the expandable member to move the expandable member toward the deployed position.

5. The downhole tool of claim 1, the at least one valve including a first valve configured to open to allow fluid to enter the chamber from the bore when a differential pressure across the first valve is greater than an opening pressure setpoint of the first valve.

6. The downhole tool of claim 1, further comprising:

a controller coupled to the at least one valve and configured to: open the at least one valve; close the at least one valve; adjust an opening pressure setpoint of the at least one valve; or adjust a closing pressure setpoint of the at least one valve.

7. A tool comprising:

a body having a flow tube and chamber therein;

a cutter block coupled to the body;

a first valve selectively connecting the chamber and the flow tube in fluid communication;

a second valve selectively connect the chamber and an external environment in fluid communication; and

a piston coupled to the cutter block, the piston being movable between first and second positions in response to pressurization of the chamber, the first position corresponding to a position in which the cutter block is extended in a radially outward position and a the second position corresponding to a position in which the cutter block is retracted in a radially inward position.

8. The tool of claim 7, further comprising:

a bias element that biases the piston toward the second position.

9. The tool of claim 7, further comprising:

a controller coupled to the first and second valves, the controller being configured to receive downlink signals and control the first and second valves in response to the downlink signals.

10. The tool of claim 7, the chamber having a radially outward boundary defined at least in part by the body and a radially inward boundary defined at least in part by the flow tube.

11. A method of operating a downhole tool, the method comprising:

tripping a drill string into a wellbore, the drill string being coupled to a downhole tool;

providing a supply fluid to the downhole tool;

transitioning the downhole tool into an active state while off a bottom of the wellbore and in response to the supply fluid being at a first pressure;

reducing a pressure of the supply fluid to a second pressure that is below the first pressure; and

maintaining the downhole tool in the active state while reducing the pressure of the supply fluid to the second pressure by maintaining a quantity of fluid in the downhole tool at or above the first pressure.

12. The method of claim 11, wherein reducing the pressure of the supply fluid to the second pressure includes providing less than 10 L/m of the supply fluid into the wellbore while maintaining the downhole tool in the active state.

13. The method of claim 11, wherein maintaining the downhole tool in the active state includes hydraulically locking the downhole tool in the active state.

14. The method of claim 11, wherein transitioning the downhole tool into the active state includes actuating a first valve, and wherein reducing the pressure of the supply fluid to the second pressure includes closing the first valve to maintain the quantity of fluid at or above the first pressure.

15. The method of claim 11, further comprising:

transitioning the downhole tool into an inactive state by at least one of: increasing a pressure of the quantity of fluid to a third pressure that is above the first pressure; decreasing a pressure of fluid external to the downhole tool; or using a controller responsive to downlink signals from a surface of the wellbore.

16. The method of claim 15, the downhole tool being configured to release the quantity of fluid when at the third pressure, and wherein increasing the pressure of the quantity of fluid includes applying a mechanical force to the drill string, the mechanical force causing an expandable member to exert a force on the quantity of fluid and increase the pressure to the third pressure.

17. The method of claim 19, wherein decreasing the pressure of fluid external to the downhole tool includes:

increasing a pressure differential across a valve to cause the valve to open; and

releasing fluid from a chamber through the valve to an external environment to cause a piston to move such that an expandable member retracts to a radially inward position.

18. The method of claim 20, wherein using the controller includes:

downlinking a signal to the controller in the downhole tool to cause a valve to open or to change a pressure setpoint of the valve;

releasing fluid from a chamber through the valve; and

causing a piston to move such that an expandable member retracts to a radially inward position.

19. The method of claim 14, wherein transitioning the downhole tool into the active state includes:

increasing a pressure differential across a first valve; and

pressurizing a chamber with the supply fluid by flowing the supply fluid through the first valve to move a piston, the piston acting to extend an expandable member to a radially outward position.

20. The method of claim 14, wherein transitioning the downhole tool into the active state includes:

downlinking a signal to a controller in the downhole tool, the downlinking signal being configured to: cause the first valve to open; change an opening pressure setpoint of the first valve; or change a closing pressure setpoint of the first valve; and

pressurizing a chamber with the supply fluid by flowing the supply fluid through the first valve to move a piston, the piston acting to extend an expandable member to a radially outward position.