MUD DEPRESSION TOOL AND PROCESS FOR DRILLING

Abstract

A downhole tool is coupled to a drill bit and having an expandable packer for reversibly isolating the bottom hole in a wellbore so that when fluid is circulated through a jet pump in the tool, a local depression of fluid pressure is formed at the drill bit. The tool body is formed of a piston and skirt which, when axially collapsed, radially expands the packer and, when extended, radially contracts the packer. The packer is rotatable with the tool through a spline arrangement. The tool remains extended for tripping until a mechanical lock is overcome. Once collapsed drilling, the toll remains collapsed due to differential pressure across a hydraulic lock. The jet pump is oriented in the tool body for minimizing tool diameter and the jet pump nozzle is offset in the pump chamber for maximizing passage of debris.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application is foreign priority benefits of Canadian application 2,527,265, filed Nov. 18, 2005, the entirely of which is incorporated herein by reference.

FIELD OF THE INVENTION

This invention relates to tools and processes for the drilling of wellbores and, more particularly, to tools and processes for localized reduction in the pressure at and around the drill bit.

BACKGROUND OF THE INVENTION

When drilling a wellbore, drilling fluid or mud is circulated down to the bit and back to surface to remove drill cuttings. The density of the mud is manipulated to keep the hydrostatic head of the mud greater than that of any pressure-producing formations encountered. This overbalanced drilling technique minimizes blowouts or other loss of control.

However, overbalanced drilling can force drilling fluids into the formation, forming a filter cake which obstructs subsequent flow of revenue fluids. Further, overbalanced drilling can retard the drill bits rate of penetration (ROP) impacting operational performance. It is believed that, as the drill bit is working to remove the pieces of formation directly in its path, this greater pressure in the mud column tends to hold the pieces in place, thus retarding the ROP. As the wells get deeper, this problem becomes more severe as the difference between the mud column pressure and the formation pressure increases. Tests by various entities in the past have determined that if the pressure at the bottom hole near the drill bit can be maintained 500-700 psi below that of formation pressure, the ROP will be very close to the maximum it can be for that type formation being drilled.

Underbalanced techniques, where the pressure exerted by the drilling fluids is less than the formation pressure, counteract some negative aspects on the reservoir and enhance other aspects of the drilling performance. Underbalanced drilling also increases control difficulty requiring additional surface equipment and techniques to avoid blowouts and ejection of the drilling string.

Similar objectives can be achieved using another approach. It is also known to use a specialized bottom hole assembly at the bit wherein one can maximize ROP by creating a localized pressure depression at the drill bit while the remainder of the wellbore thereabove is maintained at higher pressures. The pressure at the drill bit is isolated from the column of drilling fluid thereabove and techniques are used to lower the pressure at the bit.

Examples of such tools are taught in U.S. Pat. No. 4,630,691 by Hooper, Canadian patent application 2,315,969 by Hassen and Cuban patent publications CU 22503 by Gonzalez et al. and CU 22543 by Suarez.

In the prior art, CU 22503 introduces the importance of decreasing the pressure of the wellbore fluid in the bottom hole for attaining high rates of penetration, as well as the different technical methods and devices used. However, it is Applicant's belief that these techniques cannot create high depressions because they use a large cross-sectional area, which tends to be inefficient. In CU 22543, a metallic cylindrical packer is formed by two groups of equal trapezoidal wedges, located with the widest ends of the wedges of each group in opposite directions to each other. The packer is actuated by a piston and skirt system. The drill bit is supported by the skirt. Axial telescoping of the piston and the skirt slidably engage the opposing trapezoidal wedges, expanding the packer radially. The expanded packer is fixed in the expanded position only while drilling and can only negate the extra load that is produced on the upper surface of the packer due to the difference of pressure created between the upper and lower surfaces of the packer. While CU 22543 succeeds in providing some solutions to problems confronted by the depression tool of CU 22503, these solutions are themselves subject to problems and still retains other deficiencies that are common to CU 22503.

CU 22543 and CU 22503 both rotatably mount the packer to the tool, using spaced upper and lower bearings to mount both groups of trapezoidal wedges of the packer to the piston skirt system. Applicant notes that a rubber element used to isolate the upper bearing is subjected to high friction, high rotation speed, and high pressure differential in a highly erosive environment. This limits the useful life of the isolating element. Mud having solid particles and high pressure enters the bearings, shortening bearing life. As a result, the prior art packers will not close and which can force the tool to be tripped with the packer still enlarged, creating the undesirable hydraulic piston effect. Also, should the upper bearing jam, the upper part of the packer will rotate with the tool in close contact with the wellbore producing high friction and causing high torque on lateral sliding bars on the trapezoidal wedges. Operation is not feasible under these conditions.

The large cross sectional area required by CU 22543 is to accommodate the bearings and the components that mount the trapezoidal wedges to the piston skirt system that takes away from the structural integrity of the surrounding parts making up the assembly. Sliding unions between the group of upper trapezoidal wedges and the upper piece of the tool consume additional cross sectional area. Overall, the diameter of the tool needs to be further increased or the other parts of the tool have their structural integrity compromised. CU 22543 uses a form of hydraulic lock positioned between the piston and skirt which again requires a large cross sectional area. The lock arrangement is structurally weak and uses considerable cross sectional area that is detrimental to the other components of the tool. Also, the lock is not fit with a backup system to disable it in event it cannot be released by design. In this event, the packer could not be closed.

Both CU 22543 and CU 22503 use pins to transmit drilling torque to the bit. The pins are not structurally sound and use considerable cross sectional area. Any deformation of these pins would affect the transmission of torque and also affect axial force to the bit.

As set forth above, the various deficiencies of CU 22503 and CU 22543 consume a large cross-sectional area which is inefficient and exacerbates the piston effect in and out of the wellbore. Further, the main components of the Cuban tools must be stacked axially to try to accommodate the cross sectional area. Another result is that their jet pump is located higher than the packer, thus taking away from the objective of having the pressure depression effect as near as possible to the bottom hole. The higher the packer, the larger the distance between the jet pump and the drilling bit located in the bottom of the well, increasing the distance between the bit where rock cuttings are produced and the annulus located above the packer. This situation results in a design of tools having shorter packer height to aid the jet pump, but which limits the effectiveness of the tool and still distances the jet pump from the bit creating a higher chance of mud passage obstruction.

Actuation of the piston skirt system in CU 22503 and CU 22543 utilizes a small axial displacement for opening and closing the packer. This is detrimental to the packer and deployment from the rig floor is difficult. A central relief valve is employed which affects the mud circulation circuit that feeds the jet pump and it also has a large diameter relief passage using considerable cross sectional area which again compromises associated parts.

Another known aspect of mud depression tools is to install a stabilizer directly above the drilling bit. Typically, the stabilizer is formed of a cylinder with a group of blades mounted to the surface of the cylinder that extend nearly to the wellbore diameter. Slots between the blades allow mud to pass to surface and eliminate piston effect. The stabilizer must be structurally sound to withstand the high lateral loads of the bit allowing the bit to drill as close to a perfect cylindrical wellbore as possible. Cylindrical wellbores are important for running casing as casing has a larger diameter and is more rigid than drill string.

CU 22543 relies on the packer to centralize. However, when the packer is subjected to the variable lateral loads mentioned above, they are transferred to the sliding unions between trapezoidal wedges. These loads can cause the unions to eventually lose operation and eventually impeding operation of the packer to close when required. Further, CU 22543 does not provide means to keep the trapezoidal wedges parallel to the axis of the tool, affecting the wedges ability to act as a group and making the packer inoperable.

CU 22503 proposes the use of a venturi of oval cross section. The jet stream from the jet pimp's nozzle divides the venturi into two equal parts. While this offers some improvement for rock cutting transfer, the double space required reduces the high pressure depression ability of this pump. CU 22543 proposes the use of a jet pump with a venturi of variable dimensions to increases its internal diameter should a piece of rock become an obstruction therein. Operation of the jet pump is unpredictable because the low pressure created in the venturi causes the variable venturi walls to collapse, thus making the rock cutting problem worse. This variable venturi also uses considerable cross sectional area.

In prior art patent application CA 2,315,969, a jet pump is again used to create the depression effect in the bottom hole and uses commercially available packers made of rubber or other elastic materials to isolate the annulus above the bit. These elastomeric packers, or packer cups, are shaped as a cone or as a cylinder and are preferably mounted to the tool on a metal base with bearings. The mud depression tool also proposes the use of a flow control valve above the drilling bit to regulate the quantity of fluid that is passed through the bit. To maintain the low pressure created by the jet pump below the packer when fluid is not circulating, it proposes placing a metal ball within the diffusion cone of the jet pump. The metal ball is a check valve to stop flow from above the packer. It is also proposed to mount a seal of elastic material around the nozzle of the jet pump, closing the nozzle with a ball type valve. In other embodiments of the tool, use of packers with outside diameters larger than the diameter of the well with the same valves mentioned above is proposed.

Applicant does not believe that the technology of application CA 2,315,969 does not solve any of the difficulties that plague the conventional mud depression tools which use a device to hydraulically isolate the bit from the rest of the well and a jet pump to lower the pressure in the annulus that surrounds the bit. Applicant believes that new problems are introduced.

The packers of CA 2,315,969 have little lateral displacement so the wellbore must have a high degree of structural integrity. The majority of these packers are not designed to seal and be moved along the wellbore at the same time. Those that are capable of doing this can not do it under high pressures for a prolonged time or considerable distances along the wellbore. CA 2,315,969 recommends the packer use small amounts of rotation, pressure, and axial displacement, actions contrary to the main purpose of increasing ROP. While tripping in or pulling out of the well, this tool has a diameter close to the wellbore. The piston effect is created with this packer, blocking the flow of mud around the outside of the packer, and hydraulic communication through the inside of the tool is poor. Further, should drilling fluid circulation be established while not drilling, such as while reaming or circulating off bottom, the pressure depression effect is created which is disadvantageous to these operations.

The tool of U.S. Pat. No. 4,630,691 uses a plug centralizer, mounted on bearings for isolating the bit from the rest of the well, comprising an elastic material that expands under hydrodynamic pressure created in the drill string while circulating. The amount of expansion is limited by metal elements which keep its maximum diameter close to the wellbore. The depression effect is created using an annular jet pump. A rubber plug centralizer is mounted on bearings which, as disclosed previously, is not sustainable for ongoing drilling and takes consumes significant tool cross sectional area. Elastic material used as the main body of the packer is limited as the pressure downhole commonly reaches hundreds of atmospheres. For example, take a well of average depth of 3000 m where the mud has a specific weight of 1.2 g/cm3. The hydrostatic pressure will reach a value of 360 atmospheres. The rubber element suffers deformation, even before the pressure differential produced by the jet pump is considered. This is not an effective means to control the pressure downhole. Further, U.S. Pat. No. 4,630,691 uses hydrodynamic pressure for expanding the plug centralizer which creates a depression effect when circulating or reaming off bottom which stimulates the entrance of formation fluids. This scenario worsens if the drill bit is moved up at same time there is circulation, which is common practice.

In U.S. Pat. No. 4,630,691, the annular nozzle used in the jet pump requires its annular slot to be narrow. This allows the total area of the slot to be small enough so the mud can reach the necessary velocity to create the required depression but is susceptible to blockage by cuttings from the bit. This is a problem common to some of the other prior art references.

Therefore, Applicant has noted some desirable objectives for operation for such bottom hole assemblies and tools, one of which includes positioning the jet pump as close to the bit as possible to maximum the depression effect. Further, it is desired to maximize annular space about the tool during while tripping in or out of the wellbore and thereby avoiding exceeding a certain external diameter relative to the wellbore to avoid creating a piston effect. The piston effect creates high differential pressure about the tool and high depressions in the well while tripping the drill string in and out which can cause loss of well control, and also cause wellbore damage as variations in formation pressure can adversely affect the sides of the wellbore. Sticking of the drill string, due to accumulation of debris above a tool, is also a hazard, further accentuating the piston effect. If a tool has too large of a diameter while running into the wellbore, the piston effect can cause the formation to be pressurized and be damaged. It is also desirable to permit circulation of fluid during tripping in and out of the well without triggering the packer and introducing the piston effect. Further, known jet pump technology is also prone to blockage due to small jet pump passageways.

SUMMARY OF THE INVENTION

A tool is provided which is located above the drill bit to reversibly isolate the bottom hole, at the drill bit, from the rest of the wellbore so as to enable a local decrease of the pressure (depression) of drilling fluid at and around the bit. Fluid flow through an integrated jet pump creates the pressure depression.

Embodiments of this tool use an all metal expandable packer co-rotatably mounted to the tool body for reversibly isolating the bottom of the wellbore from the rest of the wellbore uphole of the tool. When actuated, the length and full perimeter of the expandable packer forms a hydraulic resistance thereacross, so the high pressure fluid above the expandable centralizer cannot migrate to the depressed, low pressure depressed area below the packer. The packer retracts to substantially the tool diameter for minimal cross-sectional area and minimal resistance while tripping.

An embodiment of the packer is formed of circumferentially connected groups of upper and lower trapezoidal segments, opposingly oriented for axial actuation between radially contracted and expanded positions. The tool co-rotatably drives the packer. When at bottom hole, with drilling ready to start, the packer can be actuated with an axial piston and skirt system of the tool body to radially expand. The actuated packer takes the configuration of a complete cylinder that closes the annulus outside the mud depression tool. The expandable packer opens to substantially the wellbore diameter forming the packer and a full perimeter centralizer while also retaining the structural integrity common to normal stabilizers. This double function of acting as a centralizer and a packer is superior than the use of separate elements.

Adjacent bars in the groups of upper and lower trapezoidal segments are connected by longitudinal unions, such as dovetail connections, which permit relative axial movement, yet structurally control other forces on the bars that would otherwise cause them to deviate from their orientation parallel to the axis of the tool during opening and closing of the expandable packer. Such unions avoid jamming or sticking of the packer during actuation. An axially telescoping push-pull mechanism of the piston and skirt actuates the trapezoidal segments with a minimal cross sectional area of the tool. The piston axially pushes and pulls the upper trapezoidal segments while the skirt makes the same action on the lower trapezoidal segments, actuating the expandable packer between the axially collapsed and radially, expanded position to the axially extended and radially contracted position.

The expandable packer avoids troublesome bearings, being mounted to the tool's body for co-rotation with the tool. The trapezoidal segments are axially moveable yet co-rotationally constrained to the tool body. The upper trapezoidal segments are rotationally constrained by circumferentially-spaced longitudinal bars forming a spline on the tool body which enable axial movement parallel to the axis of the tool. This constant parallel engagement between this group of upper trapezoidal segments and the tool's body negates twisting from torque that could otherwise deflect the trapezoidal segments and interfere with dependable opening and closing of the expandable packer. Further, through axial engagement of the tool body and packer when radially closed for tripping, the tool has comparable tension strength to the rest of the drill string.

Acting as a centralizer, the packer has more height than the known stabilizers, while having an equivalent structural integrity, resulting in dependable centralization of the drill bit. Lateral loads on the packer/centralizer while drilling are absorbed directly by the fixed lower part of the centralizer and also by the direct contact of both groups of trapezoidal segments on the tool body. The length of the centralizer can be longer than conventional packers and having a relatively small annular gap of 0.5 to 1 mm to the wellbore when activated.

Due to a compact, radial arrangement of the main components of the piston and skirt embodiment of the tool, the jet pump, fluid passageways and the expandable packer can be positioned at about the same elevation in the tool, thereby making the operating fluid dynamics and the manufacturing of the tool very efficient.

In embodiments of the tool, a hydraulic lock holds the piston and the piston skirt in the drilling position while pumping ensuring the drilling configuration will not be lost when the drill bit is raised off bottom. Preferably, a mechanical lock releasably retains the packer in the contracted, tripping position until a certain threshold axial force is encountered, such as upon landing of the drill bit on bottom. The lock keeps the expandable packer closed, preventing premature opening until the desired position is reached. The structural capability of the hydraulic lock can be equivalent to a thread of the same strength and automatically disengages when the mud pumps stop. Should the hydraulic lock fail to automatically disengage, an emergency forced deactivation through axial displacement can be employed.

A form of jet pump, used to depress or lower the pressure of the drilling fluid in the bottom hole, is located at about same level in the tool as the piston and skirt system and the expandable packer, eliminating restrictions on the dimensions of each one of the components and allowing an increased general efficiency of the tool. The jet pump utilizes a venturi which exhausts to an area immediately uphole of the packer, which permits better cleaning and avoids the possibility of obstruction of debris from the bottom hole, thus lending increased dependability of the tool. Further, the nozzle axis of the jet pump is preferably offset within the pump's venturi chamber which increases the available area to allow passage of rock cuttings such as those about twice as large as those permitted through conventional jet pumps with little loss in efficiency. Additionally a fluid plug, used for redirecting the mud flow from the bit to the jet pump, is of considerable length so that erosion is not problematic despite implementing a minimal cross sectional area in the tool.

In another embodiment, the tool utilizes a large axial displacement of the piston and skirt to open and close the packer. The large displacement minimizes problems in deploying and operating the tool, as downhole actuation is now more apparent at the surface. Further, this large axial displacement can be used as a jar effect should the drill bit become stuck due to a drilling problem or foreign objects falling from uphole.

The trapezoidal segments are capable of transmitting high torque in the open or closed position, such as if it is desired to apply high torque to free a struck drill bit. Torque to the drill bit is transferred through the trapezoidal segments. The edges of the trapezoidal segments are fit with dovetail unions which provide efficient torque transmission

Further, the tool can endure a large axial load compared to other components in the drill string, as the trapezoidal segments are very robust and have a robust mounting system.

Therefore, various embodiments of the mud depression tool have novel and inventive characteristics including aspects of the expandable packer and centralizer, the arrangement of the components for minimal cross-sectional area, handling of fluid dynamics in the tool, and mechanical robust construction.

In a broad aspect, a downhole pressure depression tool for a wellbore is provided comprising: a tool body having an axis aligned in the wellbore and forming an annulus therebetween, the tool body adapted for connection to a tubing string extending to surface and adapted for co-rotation with a drill bit, the tool body having a fluid inlet adapted for fluid communication between the tubing string, the tool body and the drill bit; a centralizer fit to the tool body for centralizing the tool body in the wellbore while enabling flow thereby from the drill bit and uphole through the annulus; an expandable packer positioned coaxially about the tool body and co-rotatable therewith and which is reversibly and radially actuable between a contracted tripping position to enable fluid flow thereby along the annulus and an expanded drilling position to substantially isolate hydraulically an uphole annulus which is uphole of the packer from a downhole annulus which is downhole of the packer, wherein in the expanded drilling position, the expandable packer also forming at least one internal passageway between the packer and the tool body for establishing fluid communication between the uphole annulus and the downhole annulus; and a jet pump located in the tool body and having a nozzle in fluid communication with the fluid inlet and directed to the uphole annulus, the nozzle having a venturi chamber formed thereabout and in the internal passageway, wherein in the expanded drilling position, the venturi chamber has an inlet in fluid communication with the downhole annulus and a discharge in communication with the uphole annulus for depressing the pressure in the downhole annulus.

In another aspect, the packer is actuated with a piston and skirt arrangement which is axially telescopically movable to reversibly actuate the expandable packer. Preferably, a mechanical lock maintains the piston and skirt in a first tripping position so that the expandable packer is not actuated by normal movement into and out of the wellbore including forces generated by circulation of drilling fluid. For drilling, the mechanical lock is forcibly overcome before telescopically collapsing the piston into the skirt and radially deploying the expandable packer which is adapted to close the wellbore. Circulation of drilling fluid actuates a hydraulic lock for axially coupling the piston and skirt with the packer deployed.

In another aspect of the invention, the jet pump flow passageways and fluid supplied to the bit, such as through cleaning passageways, are rotationally offset so as to efficiently utilize the cross-section of the tool.

In a preferred aspect of the invention, the expandable packer is formed of two groups of circumferentially-spaced, alternating and opposing upper and lower trapezoidal segments. The respective bases of the trapezoids of each group are oriented in opposite directions forming a cylindrical packer of variable diameter. About the entire circumference of the cylindrical packer, each bar is slidably connected or united along mating radial union faces. The packer is axially movable and co-rotatable with the tool through a spline arrangement. Accordingly, torque can be transmitted from the tool, to the packer and from the packer to the skirt, and ultimately to the bit.

In another aspect of the invention, the jet pump nozzle is offset within the pump's venturi chamber for enabling passage of larger cutting and debris.

As a result of the above features and additional features as discussed herein, the tool and process for drilling can achieve high values of differential depression at the bottom hole while drilling, while using low energy to increase the productive parameters of the drilling bit. This tool has all the positive characteristics of former designs, overcomes their shortcomings and also offers solutions to other problems that are not covered by other prior art tools.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention are depicted in the drawings. The drawings which are intended to illustrate embodiments of the invention and which are not intended to limit the scope of the invention.

FIG. 1 illustrates a side view of an embodiment of the tool during tripping into or out of a wellbore. The tool is illustrated in the context of being adapted at its upper end for connection to a lower end of a drilling string and adapted at a lower end of the tool for connection to a drill bit, all of which are in situ in a wellbore;

FIG. 2 illustrates a side view of the tool of FIG. 1 rotated 90° relative to FIG. 1 and shown with the expandable packer actuated while drilling at the bottom of the wellbore;

FIG. 3 is a partial cross-section view of an embodiment of the tool of FIG. 2 with the packer actuated. The entire view left of the axis is sectioned to the axis and the view right of the axis is partially sectioned;

FIG. 4A is a cross-sectional view across the axis of FIG. 3 along A-A and illustrating the relationship of the expandable packer and piston spline;

FIG. 4B is a cross-sectional view across the axis of FIG. 3 along B-B and illustrating the packer internal venturi passageway;

FIG. 5A is a cross-sectional view across the axis of FIG. 3 along C-C and illustrating the blade centralizer;

FIG. 5B is a partial side cross-sectional view of FIG. 3 of the area marked D-D and illustrating the interface of the downhole end of the piston and the skirt;

FIG. 6 is a partial cross-section view of an embodiment of the tool of FIG. 1 with the packer in the tripping position. The entire view left of the axis is sectioned to the axis and the view right of the axis is partially sectioned;

FIG. 7A is a cross-sectional view across the axis of FIG. 6 along E-E and illustrating the hydraulic lock;

FIG. 7B is a partial side cross-sectional view of FIG. 6 of the area marked F-F and illustrating the mechanical lock assisting in preventing the piston from telescoping into the skirt;

FIG. 8A is a partial side cross-sectional view of FIG. 6 of the area marked G-G illustrating the hydraulic lock profile in the skirt;

FIG. 8B is a partial side view of FIG. 6 of the area marked G-G and illustrating the dovetail interface of the trapezoidal segments and the blade centralizer;

FIG. 9 is a cross-sectional view of an embodiment of FIG. 1 and illustrates the hydraulic porting to the annulus during circulation of mud from the surface when the tool and drill bit is off bottom. The arrows in the figure point out the fluid movement through the different passages of the tool. The cross-sectional view is full sectioned by a plane coincident with its central axis and with the central plane of the circulation circuit including the jet pump;

FIG. 10 is a cross-sectional view according to FIG. 9 and illustrates the tool cut by the same plane as in FIG. 9 except rotated 90° relative thereto and is coincident with the central plane of the second passageway or filter cleaning circuit;

FIG. 11 is a cross-sectional view of an embodiment of FIG. 1 and illustrates the hydraulic circulation while drilling. The cross-sectional view is full sectioned by a plane coincident with its central axis and with the central plane of the circulation circuit for operation of the jet pump;

FIG. 12 is a cross-sectional view according to FIG. 9 and illustrates the tool cut by the same plane as in FIG. 9 except rotated 90° relative thereto and is coincident with the central plane of the bit cleaning circuit;

FIG. 13A is a partial side cross-sectional view of FIG. 11 of the area marked J-J illustrating an embodiment of the offset nozzle jet pump; and

FIG. 13B is a partial side view of FIG. 11 of the area marked K-K and illustrating the hydraulic lock and differential pressure interface.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

General—Tool

With reference to FIGS. 1 and 2, an embodiment of a downhole mud depression tool 10 is illustrated. In FIG. 1, the tool 10 is shown in a tripping configuration for moving through a wellbore. In FIG. 2, the tool 10 is shown in a drilling configuration.

The tool 10 is illustrated in the context of a wellbore environment and adapted for being suspended in a wellbore 11 and rotationally driven such as by a drill string 12 or mud motor (not shown). The tool 10 is adapted for drivable co-rotatable connection to a drill bit 13. An annulus 14 is formed between the tool 10 and the wellbore 11. An expandable packer 15p is concentrically positioned about the tool 10 for reversibly and radially engaging the wellbore 11.

Having reference also to FIG. 3, the expandable packer 15p is concentrically positioned and actuable about a tool body 20 of cylindrical configuration. The expandable packer 15p is co-rotatable with the tool body 20. A fixed centralizer, such as a blade centralizer 16, is affixed to the tool body 20 for maintaining the tool 10 coaxial within the wellbore 11 while also permitting fluid flow thereby. When actuated to expand to substantially fill the annulus 14, the expandable packer 15p acts as a packer to fluidly separate the annulus 14 into an uphole annulus 14u and a downhole annulus 14d.

The actuated expandable packer 15p also acts as a robust centralizer 15c for the tool 10.

The tool body 20 and packer 15p are preferably manufactured of steel or a variety of materials suitable for the service and wellbore environment as known by those of skill in the art.

Drilling fluids such as drilling mud can be directed downhole from the surface for circulation of fluids through the tool 10 and back up to surface through the uphole annulus 14u during tripping or, alternately, are directed to power a jet pump 25 (FIG. 3).

During tripping, as shown in FIGS. 2 and 3, fluids are directed through the jet pump 25 and up the uphole annulus 14u for inducing fluid flow from the drill bit 13 to induce a low pressure in the downhole annulus 14d and further to direct drill cuttings (not shown), from the downhole annulus 14d, to the higher pressure uphole annulus 14u.

As shown in FIGS. 2 and 3, the tool body 20 comprises a two-piece cylindrical and telescoping arrangement of a piston 30 and a piston skirt 31. The piston 30 is adapted for drivable or co-rotational attachment to the rest of the drill string 12 through an uphole end 3, preferably threaded for connection to the drill string 12. The piston skirt 31 attaches to the drill bit 13 at a downhole end 4, such as through a female box end threaded connection. Herein the terms “uphole” and “upper” can be used interchangeably regardless of application in vertical, slant and horizontal orientations. Similarly, the terms “downhole” and “lower” are used interchangeably.

The piston 30 is axially, telescopically and movably guided in the piston skirt 31 and, in one embodiment, is lockable in either a telescopically extended position for tripping or a collapsed position for drilling.

The piston 30 and expandable packer 15p are fit with a cooperating spline and slot arrangement for permitting the piston 30, which can be rotated by the drill string 12, to also rotationally drive the expandable packer 15p, skirt 31, and bit 13 while still enabling relative axial movement. The expandable packer 15p is in a minimized diameter, tripping configuration (FIG. 1) when the piston 30 and skirt 31 are in the extended position and is freely movable in the wellbore 11 without causing a hydraulic piston effect. The expandable packer 15p is radially-actuated (FIG. 2) when the piston 30 and skirt 31 are in the collapsed position.

The downhole end 4 of the skirt 31 is adapted for connection to the drill bit 13. The piston 30 has a cylindrical surface for telescopically fiting to a cylindrical bore of the skirt 31. The blade centralizer 16 is affixed to the skirt 31.

The components of the tool 10 are described in greater detail as follows.

Piston and Skirt

The tool body 20 comprises the piston 30, and a skirt 31, the piston 30 being telescopically and axially movable within the piston skirt 31.

With reference to FIGS. 3 and 6, the piston 30 has a piston bore 50 for receiving fluid from the drill string 12 and through upper inlet 51. First passageways 52 alternately direct fluid from the upper inlet 51 to the skirt 31 or to the jet pump 25.

In the drilling configuration, the inlet 51 directs fluid to power the jet pump 25, depress pressure at the bit 13 and circulate fluid and cuttings to the upper annulus 14u. In the tripping configuration, the upper inlet 51 can also feed second passageways 53 extending between drill bit 13 and the uphole annulus 14u. As shown also in FIG. 4A, The first and second passageways 52,53 are distributed within a cross-section of the piston 30. The first passageways 52 generally lie in a first plane generally along the axis of the tool body 20 and the second passageways are in a second plane rotated about the tool axis.

The first passageways 52 comprise the upper inlet 51 extending along downhole portion 52a to a “U” passage 52b and back along an uphole portion 52c to the jet pump 25 and continuing uphole through a discharge portion 52d to the upper annulus 14u. Each of the downhole through discharge portions 52a,52b,52c,52d can lie on a plane common with the axis of the piston 30 however, cross sectional area of the first passageways 52 can be maximized in the piston 30 by angling the downhole portion 52a off-axis slightly to accommodate the “U” passage 52b and then directing the uphole and discharge portions 52d substantially parallel to the downhole portion 52a.

In one embodiment as shown in FIG. 6, the second passages 53 comprise one or more cleaning passages 54, preferably a pair of cleaning passages 54,54 which are located diametrically opposite each other and lie in the second plane which is common with the piston 30 however being rotated 90 degrees from the first plane of the first passageways 52, thereby occupying heretofore unused cross-section of the piston 30.

As shown in FIGS. 3 and 6, an apex of the “U” passage 52b is fit with a plug port 60. The plug port 60 leads to a fluid gallery 61 extending from the plug port 60 to a lower end 62 of the piston 30. Further, the skirt 31 supports a plug 63 which is telescopically movable into and out of the gallery 61 with the piston 30 and skirt 31 movement, to alternately block and open the plug port 60 respectively. Preferably, the gallery 61 and plug 63 are concentric in the tool body 20 to ensure alignment without requiring other means for rotationally aligning the piston 30 and skirt 31. As shown in FIG. 3, when the piston 30 and skirt 31 are in the collapsed position, the plug port 60 is blocked and fluid flows about the U-passage 52b and uphole through the jet pump 25. As shown in FIG. 6, when the piston 30 and skirt 31 are in the extended position, the plug port 60 is open and fluid can flow from the upper inlet 51, into the U-passage 52b and through the gallery 61 to the skirt 31.

Best seen in FIGS. 6 and 10, along the gallery 61 are openings 65 to the one or more cleaning passageways 54 extending uphole through the piston 30 from the gallery 61 to one or more filter ports 66 fit with filters 67 adjacent the outer surface of the uphole end 3 of the piston 30. As stated above, in one embodiment, the cleaning passageways 54 have a second plane of symmetry coincident with the central axis of the piston 30, but rotated 90° to the first plane of the first passageways 52 and jet pump 25. Each cleaning passage 54 extends from the filters 67 and filter ports 66 to the plug port gallery 61.

When the plug port 60 is open, a portion of the fluid which flows downhole through the upper inlet 51 to the “U” passage 52b and plug port 60, can also flow through openings 65 in the gallery 61 and uphole through the cleaning passageways 54,54 and out the filtered ports 66,66. When the piston 30 and skirt 31 are in the collapsed position, the plug port 60 is closed by plug 63 and fluid flow is diverted around “U” passage 52b to the jet pump 25. An upper surface of plug 63 can matche a contour of the “U” passage 52b.

At the base of the plug 63 are bypass ports 69 which align with openings 68 when the plug port 60 is closed by the plug 63 so that fluid from the uphole annulus 14u can also flow downhole from the filtered ports 66,66, through the cleaning passageways 54,54 and out the bypass ports 69 to supply filtered fluid to the drilling bit 13.

The Jet Pump

Generally, in another aspect of the invention, a jet pump arrangement is provided which improves the reliability of jet pumps handling fluids with debris. The axis of the nozzle of the jet pump is offset from the axis of the venturi for creating a large flow cross-sectional area. A fluid circuit for the jet pump and the expandable packer cooperate to pass drill cuttings.

In more detail, and with reference to FIGS. 3, 4B, and 13A, fluid powering the jet pump 25 flows about the “U” passage 52b. The jet pump 25 is supported in the piston 30 and forms a confluence between power fluid directed down the drill string 12 from surface and fluid induced by the jet pump 25 to flow uphole from the drill bit 13.

The jet pump 25 comprises a jet nozzle 80 having a fluid inlet 81 and conical jet nozzle base 82 supporting a replaceable nozzle nut 83, preferably threaded thereto. The nozzle 80 extends through a venturi chamber 85 which is in fluid communication with the lower annulus 14d through a venturi passageway 86. The venturi nozzle 80 is laterally offset in the venturi chamber 85 for maximizing passage of debris. The chamber 85 is formed by a window in a side wall of the piston 30 facing the expandable packer 15p. Uphole and downstream of the nozzle 80 is a mixing area 84 and a fluid expansion area 87 that channeled fluid through uphole passage 52d to the uphole end 3 of piston 30 for discharge to the upper annulus 14u.

The Expandable Packer

As shown in FIG. 1 and as stated above, when the piston 30 and skirt 31 are in an axially extended position, the expandable packer 15p is in a first contracted tripping position. The expandable packer is radially contracted for presenting a minimal piston effect when tripped through the wellbore 11.

As shown in FIGS. 2 and 3, the expandable packer 15p is actuable to an axially collapsed position so as to expand radially to a second expanded drilling position so as to substantially block the wellbore 11.

The piston 30, skirt 31 and packer 15p work in concert. The expandable packer 15p is positioned coaxially about the tool body 20 above the skirt 31 and which, in the drilling position, is reversibly and radially actuable to engage the wellbore 11 and thereby isolate the uphole annulus 14u above the packer 15p from the downhole annulus 14d and bit 13 below the packer 15p.

As shown in FIG. 3, in the actuated position, the venturi passageway 86 is formed as an interior passageway opened up in an annular space between the packer 15p and tool body 20. The venturi passageway 86 is in fluid communication between the wellbore 11 below the packer 15p and the uphole annulus 14u above the packer 15p. Located intermediate along the venturi passageway 86 is the venturi chamber 85 of the jet pump 25. Flow of fluid from the jet pump nozzle 80 produces a low pressure in the venturi chamber 85 and induces flow of fluid and cuttings from the drill bit 13 and uphole through the venturi passageway 86.

The expandable packer 15p is supported for co-rotation with the tool body 20 by at least one of the piston 30 or skirt 31 while remaining moveable axially with respect to one or the other. In one embodiment, the packer 15p is axially supported at a downhole end 90 at a conical surface 91 of the blade centralizer 16 for enabling actuation of the packer 15p relative to the piston 30 when the piston and skirt 31 are telescoped to the collapsed position. The packer 15p is radially supported from the piston 30 at an uphole end 92.

At the uphole end 3 of the piston 30 an upper cylindrical radial support 93 is formed to support the uphole end 92 of the packer 15p. The piston 30 further comprises a spline 95 extending along the piston 30 for enabling co-rotation of the expandable packer 15p with the tool body 20.

Downhole of the upper cylindrical radial support 93, the piston 30 transitions along a radial surface 98 and inwardly to a cylindrical spline base 94.

Best seen in FIG. 4B, the spline 95 comprises a plurality of longitudinal bars 100 spaced around the circumference of the piston 30. The bars 100 are axially-extending and stand radially outward from the spline base 94 of the piston 30. The bars 100 rotationally engage the packer 15p, such as through corresponding sockets 101 formed in the packer 15p for enabling co-rotation of the piston 30 and the packer 15p.

Best seen in FIGS. 1 and 2, the packer 15p itself comprises two groups of metal trapezoidal segments. Upper trapezoidal segments 110 and lower trapezoidal segments 111 are circumferentially-spaced in an alternating arrangement about the tool body 20. Respective and wide bases 110b,111b,110b,111b . . . of the trapezoidal configuration of alternating segments 110,111,110,111 . . . are oriented in opposite directions forming a cylindrical packer structure of variable diameter as the segments 110,111 are manipulated axially. More specifically, the lower trapezoidal segments 111 have their bases 111b located downhole and the upper trapezoidal segments 110 have their bases 110b located uphole. Together, the trapezoidal segments 110,111 form a tubular, expandable cylindrical packer 15p having a central axis which coincides with the axis of the tool body 20.

With reference to FIGS. 3, 4A and 4B, about the entire circumference of the cylindrical packer 15p, each segment 110,111 is slidably connected or united along mating radial faces 112 between adjacent neighboring segments 110,111. Either of the upper or lower segments 110,111, preferably the upper segments 110, are fit with the axially extending and radially outward extending slots or sockets 101 extending along their inner axial extent for slidable coupling with corresponding radially oriented and axially extending longitudinal bars 100 of the spline 95.

As the opposing trapezoidal segments 110,111 are axially actuated, the trapezoidal radial faces 112 the segments radially outwards varying the diameter of the packer 15p. The sockets 101 remain radially coupled with the bars 100 of the spline 95 for transmission of torque from the piston 30 to the expandable packer 15p and through the expandable packer 15p to the bit 13. Cavities 96 (see FIG. 3) can be formed and circumferentially spaced about the radial support 93 and radial transition 98 of piston 30 for rotationally engaging the upper end 92 of the upper trapezoidal segments 110 when the packer 15p is actuated.

As stated earlier, the packer 15p can be axially supported at the downhole end 90 at the conical surface 91 or upper conical portion of the blade centralizer 16. The lower trapezoidal segments 111 can be radially moveably yet retained axially at their bases 111b to the tool body 20 through angularly oriented, radially extending interlocking guides 120 (FIGS. 6 and 8B). Preferably the interlocking guides 120 are dovetail joints extending radially and downhole along the conical surface 91 of blade centralizer 16, retaining the lower segments 111 for co-movement with the skirt 31, yet permitting radial movement as the packer 15p is actuated. Accordingly, torque can be transmitted from the piston's spline 95 to at least the upper segments 110 of the packer 15p and from the packer 15p to the lower segments 111 to the blade centralizer 16, skirt 31 and ultimately to the bit 13.

With reference to FIGS. 3, 5A, 6, 8A and 8B, the blade centralizer 16 is a conical external surface of the piston skirt 31 and comprises a group of centralizing blades 121 equally spaced circumferentially thereabout and extending perpendicular from the tool 10 to substantially the diameter of the wellbore 11. Fluid is free to flow uphole between the blades 121. The centralizing blades 121 are angled relative to the axis of the tool 10 for forming vanes oriented at an angle of about 45°. The centralizing blades 121 are concentric with the piston skirt 31 and form the tool's greatest diametral extent. Upper and lower portions 122,123 of the centralizing blades 121 are conically tapered. The upper portion 122 of the centralizing blades 121 forms the upper conical surface 91 and forms a radially extending dovetail tongue 126 which is slideably coupled with radial grooves 127 formed in the base 111b of the lower trapezoidal segments 111.

At an outer radial extent of each blade 121 is a stop 128 having an external and cylindrical face at about the maximal diametral extent for limiting radial movement of the lower trapezoidal segments 111. These stops 128 are attached to centralizing blades 121 with fasteners 129. The centralizing blades 121 are fit with wear protection 125.

Returning to FIG. 4A, between the trapezoidal axially and radially extending adjacent faces 112 of the trapezoidal segments 110,111 are lateral unions formed of cooperating slots 130 and tongues 131 dovetailed to each other for retaining each neighboring segment connected to each other while permitting axial displacement therebetween. The tongues 131 and slots 130 extend along a substantial portion of the axial lengths of the segments 110,111 terminating adjacent the respective uphole end 92 and downhole end 90 of the packer 15p. Equal numbers of upper and lower trapezoidal segments 110,111 are provided.

The outer diameter of the packer 15p is about the same diameter as the diameter of the blades 121 of the blade centralizer 16. The external, wellbore-facing surfaces of the trapezoidal segments 110,111 are preferably treated for wear protection to combat the erosion from the walls of the wellbore 11. The interior surfaces of the upper and lower trapezoidal segments 110,111 are cylindrical and have about the same diameter as the spline base 94 of piston 30.

As shown in FIG. 6, and to maintain axial integrity, there are circumferentially extending uphole annular grooves such as an upper stop groove 140 and a circumferentially extending downhole annular groove or lower stop groove 141 spaced apart axially along the interior cylindrical surface of each one of the lower trapezoidal segments 111. Extending radially from the external surface of the spline base 94, there is group of longitudinal stop bars 142 (see FIGS. 3 and 6). Longitudinal stop bars 142 extend radially from the piston 30 and are located circumferentially intermediate each of the bars 100 of the spline 95.

The stop bars 142 are shorter in axial length than the spline bars 100 and are preferably equal in number. The radial depth of the upper groove 140 corresponds with the radial projection of the longitudinal bars 142. Similarly, the lower stop groove 141 accepts latches 144 extending radially outward from piston skirt 31.

When the packer 15p is in the contracted position, upper stop groove 140 cooperates with an uphole shoulder of bars 142 of the piston 30 and lower stop groove 141 cooperates with a downhole shoulder of latches 144 of the skirt 31 so as to transfer axial loads between the piston 30, the packer 15p and the skirt 31. The longitudinal segments 111 of the packer 15p arrest axial movement in the extended position and thereby provide great axial tensile strength.

During tripping, when the piston 30 and skirt 31 are in the axially extended position, the skirt 31 hangs from the latches 144 which engage the lower stop groove 141. Thus the skirt 31 is axially supported from the packer 15b. Further, the upper stop groove 140 of the packer 15p engages the longitudinal stop bars 142 on the piston 30 and thus the packer 15p hangs from the piston 30. Therefore, the tension capability of the tool is maintained through positive connections therealong which is comparable to the rest of the drill string 12.

As shown in FIG. 3, at least one bar 100 of the stop bars 142 is shorter than the others, forming a shortened bar 150. The material absent from the shortened bar 150 and its corresponding cavity slot or inner radial face of the trapezoidal segment forms an internal fluid passageway between the packer 15p and the spline base 94 of the piston 30 which forms the venturi passageway 86. The venturi passageway communicates between the annulus 14d below the packer 15p and the venturi chamber 85 intermediate axially along packer 15p.

In one embodiment, as detailed in FIG. 7B, a first lock 40, preferably mechanically actuated, releasably retains the piston 30 and skirt 31 in the extended position, see FIG. 6, until actuated to the collapsed position of FIG. 3. In another embodiment, as detailed in FIG. 13B, a second lock 41, hydraulically actuated, releasably retains the piston 30 and skirt 31 in the collapsed position of FIG. 3.

Mechanical Lock

Generally, the first, mechanical lock 40 comprises a spring ring positioned at a mechanical lock interface between piston 30 and skirt 31. The spring ring is fit to an annular slot. In the tripping position, the normal diameter of the spring ring overlaps the mechanical lock interface and prevents axial telescoping of the piston and skirt. The mechanical lock interface is beveled. When sufficient axial load is applied, such as at the commencement of drilling, the radial loads at the beveled interface compress the spring ring into the annular slot, releasing the piston 30 from the skirt 31.

In more detail, and with reference to FIGS. 6 and 7B, the mechanical lock 40 is located adjacent the lower end 62 of piston 30. The lower end 62 of piston 30 is fit with both a hydraulic lock groove 160 discussed below and a mechanical piston ring groove 170.

The mechanical lock 40 cooperates with a beveled uphole corner or face 171 at an upper end 172 of the skirt 31. The ring groove 170 is formed as an annular groove. Preferably, the upper 170u and lower sides 170d of ring groove 170 are conical and parallel. A radially compressible, piston stop ring 173 of a parallelogram cross-section is fit to the angled ring groove 170. Interior and exterior surfaces of the piston stop ring 173 are cylindrical and upper and lower surfaces are conical having the same conical angle as the upper and lower sides 107u,170d of ring groove 170 for enabling diametral contraction and expansion therein. Diametral variation of the ring 173 is enabled by sectioning the ring or using a discontinuous ring forming at least two free ends with a pre-determined space between them for enabling compressive contraction of the ring 173 from a normally expanded position. A height of a traverse section of the piston stop ring 173 is substantially equal to a height of the ring groove 170 and its radial depth is less than the depth of groove 170 for residing wholly within when compressed. When the piston 30 and skirt 31 are in the telescopically extended position, the piston stop ring 173 is radially movable within the ring groove 170 to stand out from the piston 30, preferably to a distance about equal to the annular thickness of the piston skirt 31 at its upper end 172, so as to engage the cooperating skirt beveled face 171.

As shown in more detail in FIG. 7B, a beveled downhole corner or face 175 of the piston stop ring 173 stands out radially from the surface of piston 30 and has a conical form with about the same angle as the skirt's uphole face 171 in such way they contact face to face. A vertex of the conical bevel of the ring groove 170 is opposite to the vertex of the beveled faces 171,175. The beveled faces 171,175 restrain telescopic coupling of the piston 30 and skirt 31 until a threshold axial force can drive the ring 173 radially inwardly in ring groove 170. Thus, to release the mechanical lock 40, as illustrated in the transition between the configuration shown in FIG. 6 and FIG. 3, a sufficient or threshold axial force between the piston 30 and skirt 31 radially compresses the ring 173 into groove 170 until the piston 30 can fit into the skirt 31, telescopically collapsing the tool 10.

Hydraulic Lock

Generally, the second, hydraulic lock 41 ensures the expandable packer 15p remains actuated during drilling. Once actuated, annular profiles of radially actuable hydraulic lock elements in the piston 30 align with corresponding annular profiles in the skirt 31. The skirt's annular profiles are in fluid communication with the low pressure annulus below the packer. The hydraulic lock elements are in fluid communication with the high pressure drilling fluid flowing to the bit. Differential pressure between drilling fluid at the bit and the downhole annulus drives the hydraulic lock elements and annular profiles into engagement with the skirt's annular profiles, axially locking the piston 30 and skirt 31.

In greater detail, and with reference to FIGS. 3, 8A and 13B, the hydraulic lock 41 is located adjacent the lower end 62 of piston 30 and cooperates with the upper end 172 of the skirt 31. An actuable member on the piston 30 having an annular sleeve 180 is hydraulically actuated to interact with an annular lock profile 181 in the bore of the piston skirt 31. Correspondingly, the annular lock profile 181 in the bore of the skirt 31 comprises a set of annular grooves 182 (see FIG. 8A), each groove having an upper face or shoulder 182 substantially perpendicular to the tool axis, and a lower conical cam face 183.

The piston 30 is fit with a hydraulically actuable annular band 185 radially movable in the annular hydraulic lock groove 160 formed in the piston 30. The annular band 185, such as a steel band, comprises two of segments sectioned at least once along the circumference of the band 185. The annular band 185 can form a substantially continuous 360 degree surface while enabling radial expansion. The unactuated external diameter of the band 185 is slightly smaller than the external diameter of the piston 30. The annular band 185 comprises annular projections 186 having a profile corresponding to match the set of annular grooves 182 formed in the piston skirt 31 including uphole conical cam faces 187.

The annular band 185 is radially actuable by the steel sleeve 180. Radially inward of the band 185 is the steel sleeve 180 of about the same axial height as the band 185. This hydraulic lock sleeve 180 is also segmented at least once along its circumference and the sleeve's segments are oriented so that free ends are positioned about 180° relative to free ends of the annular band 185 for forming a hydraulically actuable member. The band 185 and sleeve 180 are normally biased to a radially contracted, unactuated position.

With reference to FIG. 8A, the piston skirt 31 has one or more low pressure ports 190 extending between the lower pressure downhole annulus 14d and the set of annular grooves 182. The ports 190 preferably extend to the downhole annulus 14d below the centralizing blades 121. With reference to FIG. 13B, one or more high pressure ports 191 extend between high pressure fluid in the bore of the piston 30 and the lock groove 160. Differential pressure between the annulus 14d, as communicated through the lower pressure ports 190, and the piston bore, as communicated through the high pressure ports 191, expand the sleeve 180 and the lock band 185. When aligned axially, the lock band 185 engages the set of annular grooves 182.

In Operation

With reference to FIGS. 1 and 2, the operation of the tool for the two configurations is illustrated. As shown in FIG. 1, the tool is configured for tripping in or pulling out of the well. As shown in FIG. 2, the tool is configured for drilling.

Tripping

In the tripping position of FIGS. 9, 10 and FIGS. 1 and 6, and shown in more detail in FIGS. 6 and 7B, latches 144 of the piston skirt 31 engage the lower stop groove 141 of lower trapezoidal segments 111 so as to prevent further separation of the piston 30 and skirt 31.

To complete an axial load path between the skirt 31 and the piston 30, the longitudinal bars 142 of the piston 30 engage upper stop grooves 140 of the lower trapezoidal segments 111, limiting the travel of piston 30 to the extreme position illustrated in FIGS. 1 and 10. The two groups of trapezoidal segments 110 and 111 are retracted close to the piston 30 to minimize their diameter. The trapezoidal segments 110,111 are axially displaced relative to each other and positioned close to the central axis of the tool 10 so that the packer 15p has a small external diameter similar to that of the upper radial support 93. The segments 110,111 reside between the piston's uphole end 3 and the blade centralizer 16. The base of 110b of upper trapezoidal segments 110 are nested below the upper cylindrical radial support 93 and the interior surfaces rest against adjacent the spline base 94 of piston 30. Best shown in FIG. 9, the longitudinal bars 100 of the spline 95 engage the upper trapezoidal segments 110.

As shown in FIG. 8B, the lower trapezoidal segments 111 are guided by the engagement of the radially extending dovetail interlocking guides 144 at the downhole end 90 of the lower segments 111.

Without a pressure differential in the tripping position, as shown in FIG. 9, the hydraulic lock 41 is inactive with the hydraulic lock sleeve 180 and band 185 being recessed inside the groove 160. The plug 63 attached to the piston skirt 31 is axially displaced downhole from the open gallery 61.

With reference to FIG. 7B, the piston stop ring 173 of the mechanical lock 40 is partially in groove 170 and protrudes outside of the external cylindrical surface of the downhole end 62 of the piston 30. The beveled corner 171 of the piston skirt 31 contacts the beveled corner 175 of the piston stop ring 173.

The tool remains in the extended position due to the forces that act on the piston skirt 31 including: the weight of the drilling bit 13, the piston skirt 31 and the lower trapezoidal segments 111. Further, resistant forces are produced by the mechanical lock of the piston stop ring 173, regulated by controlling the angle of the bevel surfaces 171,175, the angle of the ring 173 in groove 170 or the thickness of the piston stop ring 173. Further, when circulating, another force is created by the pressure differential between the inside of piston skirt 31 and the annulus 14.

When tripping in and pulling out, the tool 10 can be subjected to torsion and tension loads that are generally quite low, such as those which can occur when reaming the wellbore and which are transmitted from the surface through the drilling string to the piston 30. In the configuration shown in FIG. 6, the tool 10 transmits the torque to the drilling bit 13 by transmitting the rotational moment of the piston 30 to the upper trapezoidal segments 110 through the longitudinal bars 100 of the spline 95. The lower trapezoidal segments 111 transmit torque to the piston skirt 31 through centralizing blades 121. The skirt 31 transmits torque to the bit 13. Tension loads are limited by the same means that limits the exit of piston skirt 31 from piston 30 as previously described. The tool 10 and bit 13 are suspended from the drilling string 12. Axial forces are transmitted between the longitudinal stop bars 142 of the piston 30 to the upper trapezoidal segments 110 and to the angled latches 144 of the skirt 31.

With reference to FIGS. 9 and 10, a common operation during tripping in and pulling out of the well is circulation through the drill string. FIG. 9 illustrates fluid circulation inside the tool to the annulus 14. Fluid flows into the first passageway 52 and to the “U” passage 52b where the fluid circulation splits, part goes through the open plug port 60 to the gallery 61 and part to the jet pump 25 for discharge to the uphole portion 52c and through the expansion area of the uphole portion 52c to the uphole annulus 14u.

Best shown in FIG. 10, the fluid through the gallery 61 also splits, part goes to piston skirt 31 from where it passes through the circular bypass ports 69 of the plug 63 to the inside of the bit 13 and from there for discharges to the annulus through bit nozzles (conventional, not detailed). Another part of the gallery 61 fluid flow discharges directly to the downhole annulus 14d through low pressure ports 190 (see FIG. 8A) of the piston skirt 31. Lastly, part of the fluid that enters the gallery 61 passes through the openings 65 to the cleaning passageways 54 and to the filter ports 66. This flow of fresh fluid through the filters ports 66 cleans the filters 67 of debris that may have obstructed the filters from earlier drilling operations.

When tripping the tool 10 into the wellbore 11 the same process of circulation of fluid described previously takes place but can flow in reverse, flowing from the annulus 14 to inside the tool 10 and tubing string 12. This level of hydraulic communication diminishes the piston effect of the drilling string 12 and tool 10 during movement.

Drilling

With reference to FIGS. 11 and 12 and FIGS. 2, 3, 4A and, for drilling operations, the bit 13 is on the bottom of the wellbore 11.

The bit 13 is loaded, part of the load being the weight of the drill string 12 imparted through piston 30. The forces are greater than those experienced during tripping and the mechanical lock 40 is overcome, and with reference again to FIG. 7B, the upper conical beveled corner 171 of piston skirt 31 forcibly contacts the beveled lower surface 175 of the piston stop ring 173 and drives the ring's upper beveled surface against the upper beveled surface of its groove 170. The piston stop ring 173 compresses radially and into the interior of its groove 170 until the piston 30 advances into the interior throat or bore of the piston skirt 31 and telescopically collapses.

As the piston 30 advances telescopically into the piston skirt 31, as shown in the transition from FIG. 6 to FIG. 3, the radial surface 98 is contacted by the base 110b portions of the upper trapezoidal segments 110 forcing the segments to move axially towards lower trapezoidal segments 111, slipping on the sliding lateral unions 130,131 that unite the neighboring segments 110,111. With the advance of piston 30 inside the piston skirt 31 and the simultaneous advance of upper trapezoidal segments 110 among the lower trapezoidal segments 111, both groups of segments 110,111 move radially away from the centre of the tool 10 to enlarge its external diameter. This movement continues until the inside surfaces of the group of upper trapezoidal segments 110 is larger than conical surface 98 of piston 30. When this happens, the upper trapezoidal segments 110 are substantially completely within the group of lower trapezoidal segments 111. The slot-engaging tongues 131 (FIG. 4A) of the lower trapezoidal segments 111 can be fully contacted into the slots 130 of the upper trapezoidal segments 110. The external diameter of the two groups of trapezoidal segments 110,111 is equal to the diameter of the centralizing blades 121 of piston skirt 31 with their external surfaces closing the annulus 14 at this point. The cylindrical interior surfaces of upper trapezoidal segments 110 and lower trapezoidal segments 111 are concentric with the central axis of the tool 10 and have a diameter of about the wellbore 11.

The bases 111b of lower trapezoidal segments 111 have moved out and downhole relative to the lengthened grooves 127 of centralizing blades 121 until contacting the stop 128. As a result of moving away from the centre of the tool 10 the two groups of trapezoidal segments 110,111 form the venturi passageway 86.

Piston 30 continues its advance into the skirt 31 and the plug 63 enters the gallery 61 of piston 30.

This telescopic action continues until the lower end 62 of piston 30 fully engages the piston skirt 31. As this happens, the cylindrical surface piston 30, such as that defined by the spline base 94, is completely inside of the cylindrical surface made by the interior surfaces of upper and lower trapezoidal segments 110,111, and the plug 63 is completely inside the plug port 60. Typically, the bottom of the piston 30 is still spaced a distance “D” (see FIG. 5B) above the bottom of skirt 31.

Longitudinal bars 100 of the spline 95 and stop bars 142 of piston 30 are close to the upper end of piston skirt 31 and can engage angled end projections 199 (FIG. 7B) extending from the upper end of the piston skirt 31. The upper trapezoidal segments 110 will engage the cavities 96 on (see FIGS. 2 and 5A).

With reference to FIGS. 11 and 12, surface pumps for circulation of fluid can be started and the drill string 12, or mud motor, is rotated while holding the string axially. As shown in FIG. 11, a fluid circuit for feeding the jet pump 25 begins with a flow of fluid from the drilling string 12 into the piston 30 through inlet 51 to the “U” passage 52b and to the nozzle 80 of the jet pump 25. High speed fluid is forced out of the nozzle 80 to contact fluid in the venturi chamber 85, dragging fluid towards the mixing area 86 and creating a pressure depression. This depression effect is transmitted through the venturi passageway 86 to the bottom hole of the wellbore 11 around the bit 13. The fluid exiting nozzle 80 draws fluid and rock cuttings from the bottom hole for discharge and through venturi passageway 86 into the annulus 14u above the now expanded expandable packer 15p. Fluid and rock cuttings are carried up the annulus 14 to surface.

Turning to FIG. 12, a cleaning circuit is also created by a pressure differential created by the jet pump 25 between the uphole annulus 14u located above the expandable packer 15p and the downhole annulus 14d of the bottom hole. This recirculation circuit forms starting with the high pressure fluid in the annulus 14u at the filters 67. Fluid from the annulus 14u passes through filters 67 and filter ports 66 and is pushed through the cleaning passageways 54 and to the bypass ports 69 of plug 63 and to the bit 13. From the bit 13, the fluid exits through nozzles (conventional—not shown) in the bit 13 toward the bottom hole BH forming the fluid flow which carries any rock cuttings to the venturi passageway 86 and up the annulus 14 above the expandable packer 15p. There is a minimal pressure loss through the cleaning circuit so that the pressure at the filters 67,67 is about the same as pressure at the bit nozzles.

With reference also to FIG. 13B, the bypass ports 69 of piston 30 also transmit high pressure to the one or more high pressure ports 191 of the interior portion of the hydraulic lock sleeve 180 and band 185 located in the lock groove 160. The radially outward face of hydraulic lock bands 185 is ported to the low pressure port 190 (FIGS. 6 and 8A) to equalize with the low pressure area in the bottom hole BH around the bit. The pressure difference between radially interior and exterior surface of the hydraulic lock band 185 forces the band to expand, engaging the annular projections 186 into the interior grooves 182 of the piston skirt 31. The lock 41 is restrained from expanding completely into place due to the relative axial displacement “D” that exists between the piston 30 and skirt 31. As the weight on bit 13 is allowed to drill off, piston skirt 31 is pulled down forming the clearance distance “D”. Drilling off comprises holding the drill string 12 axially while rotating the string as the bit drills. The weight of the bit 13, piston skirt 31, and the lower trapezoidal segments 111 pull on the skirt 31. The annular projections 186 of the hydraulic lock 41 line up with the annular grooves 182 of piston skirt 31, thus enabling the annular band 185 to lock into the annular grooves 182.

The flow of the surface pumps, set to drilling rate, operates the jet pump 25 for forming a pressure differential from the higher pressure above the expandable packer 15p and the lower pressure therebelow. The pressure differential adds to the weight on bit 13 as the product of the cross-sectional area of the expandable packer 15p and the pressure differential. This force is transferred from the skirt 31, through the hydraulic lock 41 to the piston 30 and drill string 12. This extra force stretches the drill string 12 while it is anchored axially and rotating at the rig floor of a drilling ring at surface (not shown). Advancement of the bit 13 stops once the forces equalize. The value on the weight indicator at this moment, less the weight of the string in the non-pumping (static) mode, determines the depression being developed below the expandable packer 15p. This value is used to drill ahead.

While drilling, the mud depression tool is subjected to tension that is transmitted to the drilling string 12 with the operation of the hydraulic lock 41. Tension results because the supplementary axial hydraulic weight is greater than the axial weight the bit 13 needs while drilling.

As shown in FIGS. 3 and 11, torque to turn the bit 13 and the expandable packer 15p comes from the drill string 12 to the piston 30 and to the piston skirt 31 via the expandable packer 15p. The piston skirt 31 transmits the torque directly to the drill bit. Further, torque transmission is aided from the side of the notches 96 of the area below radial surface 98 to the upper trapezoidal segments 110 (FIG. 4A). The lower trapezoidal segments 111 rotate the centralizing blades 121 of the piston skirt 31. Torque to the upper and lower trapezoidal segments 110,111 equalize through the radial union 112 of the sets of segments 110,111.

Radial forces exposed to the expandable packer 15p from the drill bit 13 are mostly negated by the fixed part of the blade centralizer 16. What little force remains is absorbed by the upper trapezoidal segments 110 and lower trapezoidal segments 111 which transfer the force to the piston 30. There is a minimal tendency for fluid to migrate around the expandable packer 15p, as the small clearance between the expandable packer and the wellbore 11 tends to fill with rock cuttings from the bit. Preferably, the trapezoidal segments 110 and 111 are hard surfaced to protect them from erosion due to contact from the wellbore 11.

As shown in FIGS. 9 and 10, when drilling is stopped and it is desired to lift the bit 13 to add a single length of dill pipe or to pull out of hole, the tool 10 is collapsed as follows. When the circulation stops, the depression effect of jet pump 25 ceases and the pressure equalizes above and below the expandable packer 15p. The hydraulic lock 41 collapses to its biased, unactuated position as the pressure equalizes. The piston 30 is freed from piston skirt 31 and the weight of the bit 13 and skirt 31 cause the skirt to telescopically extend from the piston 30. The piston 30 and upper trapezoidal segments 110 pull axially out from the lower trapezoidal segments 111. The axial movement causes the trapezoidal segments 110,111 to contract radially to a smaller diameter while extending. The expandable packer 15p collapses axially. The expandable packer 15p axially engages the piston 30 and skirt 31. The interaction of the piston 30, expandable packer and skirt 31 stops the relative axial movement between piston 30 and piston skirt 31. The tool returns to the configuration in FIGS. 1 and 6.

If the hydraulic lock 41 does not release as the pressure is equalized, a mechanical alternative is provided to ensure deactivation and release. In this situation, hydraulic lock 41 can be forcibly retracted into groove 160 by discharging part of the weight of the drilling string 13 onto piston 30, closing distance “D” (FIG. 5B), between the lower end of piston 30 and the bottom of piston skirt 31, which drives piston 30 further inside of piston skirt 31. The angled lower profile of the annular grooves 182 forms the uphole conical cam face 183 which exerts an inward radial force on the downhole conical cam face 187 of the corresponding annular projections 186, driving the band 185 radially inwardly and releasing the piston 30 from the skirt 31.

Claims

1. A downhole pressure depression tool for a wellbore comprising:

a tool body having an axis aligned in the wellbore and forming an annulus therebetween, the tool body adapted for connection to a tubing string extending to surface and adapted for co-rotation with a drill bit, the tool body having a fluid inlet adapted for fluid communication between the tubing string, the tool body and the drill bit;

a centralizer fit to the tool body for centralizing the tool body in the wellbore while enabling flow thereby from the drill bit and uphole through the annulus;

an expandable packer positioned coaxially about the tool body and co-rotatable therewith and which is reversibly and radially actuable between a contracted tripping position to enable fluid flow thereby along the annulus and an expanded drilling position to substantially isolate hydraulically an uphole annulus, which is uphole of the packer, from a downhole annulus, which is downhole of the packer wherein, in the expanded drilling position, the expandable packer also forms at least one internal passageway between the packer and the tool body for establishing fluid communication between the uphole annulus and the downhole annulus; and

a jet pump located in the tool body and having a nozzle in fluid communication with the fluid inlet and directed to the uphole annulus, the nozzle having a venturi chamber formed thereabout and in the internal passageway, wherein in the expanded drilling position, the venturi chamber has an inlet in fluid communication with the downhole annulus and a discharge in communication with the uphole annulus for depressing the pressure in the downhole annulus.

2. The tool of claim 1 wherein:

the tool body adapted for connection to the tubing string further comprises a piston adapted for connection to the tubing string;

the tool body adapted for connection to the drilling bit further comprises a skirt adapted for connection to the drill bit; and

the piston is axially telescopically movable in a bore of the skirt between an axially extended position and an axially collapsed position for actuating the expandable packer between the contracted tripping position and the expanded drilling position.

3. The tool of claim 2 wherein the expandable packer is actuable by the piston and skirt, and wherein the expandable packer is actuated between the contracted tripping position and the expanded drilling position as the piston and the skirt axially telescope between the extended position and the collapsed position respectively.

4. The tool of claim 1 further comprising:

first passageways fluidly extending between the fluid inlet and the annulus uphole of the packer through the jet pump and between the fluid inlet and the drill bit; and

second passageways fluidly extending between the upper annulus and the bit.

5. The tool of claim 4 wherein the first passageways are oriented along the tool body in a first plane through the axis and the second passageways are oriented along the tool body in a second plane through the axis which is rotationally offset from the first passageways.

6. The tool of claim 3 wherein:

in the extended position, the fluid inlet is fluidly connected to the jet pump and to the drill bit; and

in the collapsed position, the fluid inlet is fluidly connected to the jet pump and isolated from the drill bit and the upper annulus is fluidly connected to the bit.

7. The tool of claim 6 further comprising:

a plug port formed in the piston; and

a plug formed in the skirt, wherein in the extended position, the fluid inlet is fluidly connected to the drill bit through the plug port; and in the collapsed position, the plug blocks the plug port for isolating the bit from the fluid inlet and directing fluid o the jet pump, the port having bypass passages formed therein for fluidly connecting the bit and the upper annulus.

8. The tool of claim 1 wherein the jet pump venturi chamber is formed as a window in a side wall of the tool body and thereby is in fluid communication with the internal passageway.

9. The tool of claim 8 wherein the jet pump nozzle is offset in the venturi chamber for forming a large cross-section.

10. The tool of claim 1 further comprising radially outward standing and axially-extending bars along and distributed circumferentially about the tool body for forming a spline and corresponding axially extending sockets in the expandable packer for enabling radial movement of the packer relative to the tool body and co-rotation of the expandable packer with the tool body.

11. The tool of claim 10 wherein the expandable packer further comprises:

a plurality of upper trapezoidal segments spaced circumferentially about the tool body, each upper trapezoidal segment having a wide base which is oriented uphole;

a plurality of lower trapezoidal segments spaced circumferentially about the tool body each lower trapezoidal segment having a wide base which is oriented downhole, and wherein

each lower trapezoidal segment is spaced from each other lower trapezoidal segment by an upper trapezoidal segment and connected at radial faces for relative sliding axial movement, the lower and upper trapezoidal segments forming a cylindrical packer of variable diameter which is arranged substantially coaxial with the tool body.

12. The tool of claim 11 wherein:

the centralizer is a blade centralizer comprising a plurality of blades extending radially and angularly extending downhole from the skirt below the packer, a blade corresponding to each of the packer's lower trapezoidal segments; and

a slidable connector between each of the lower trapezoidal segments and a corresponding blade for enabling radial and angular movement along the blade for permitting variation of the diameter of the packer between the contracted and expanded positions.

13. The tool of claim 12 wherein two or more of the upper trapezoidal segments each have an axially extending and radially outward extending cavity formed from an inner surface as the socket corresponding to each of the radially outward standing and axially-extending bar of the spline.

14. The tool of claim 13 wherein:

the skirt further comprises two or more first latches circumferentially about and extending radially outwardly from an uphole end of the skirt;

the lower trapezoidal segments further comprise a circumferentially extending downhole annular groove in the inner surface at a downhole end of the lower trapezoidal segments, wherein when the expandable packer is in its contracted tripping position, the first annular groove is positioned radially inward to engage the latches, supporting the skirt axially from the lower trapezoidal segments.

15. The tool of claim 14 wherein:

the piston further comprises two or more second latches spaced circumferentially about and extending radially outwardly from the piston;

the lower trapezoidal segments further comprise a circumferentially extending uphole annular groove in the inner surface and spaced uphole from the first annular groove, wherein when the expandable packer is in its contracted tripping position, the second annular groove is positioned radially inward to engage the latches, supporting the lower trapezoidal segments axially from the piston.

16. The tool of claim 3 further comprising a first lock for maintaining the piston and skirt in the extended position and releasable upon application of a threshold axial force.

17. The tool of claim 16 wherein the first lock comprises:

an annular lock groove formed adjacent a downhole end of the piston; and

a compressible ring fit to the annular lock groove and having an uncompressed diameter greater than that of the bore of the skirt wherein upon application of the threshold axial force between the piston and the skirt, the compressible ring is compressed into the annular lock groove releasing the piston to telescope into the skirt.

18. The tool of claim 17 wherein:

the annular lock groove further comprises conical uphole and downhole walls; and

the compressible ring has conical uphole and downhole walls corresponding with the conical uphole and downhole walls of the annular lock groove for increasing the threshold axial force required to release the first lock.

19. The tool of claim 15 wherein the compressible ring has a beveled downhole face and wherein, in the tripping position, the beveled downhole face engages a beveled uphole face at the uphole end of the skirt.

20. The tool of claim 16 further comprising a second lock for maintaining the piston and skirt in the collapsed drilling position during drilling.

21. The tool of claim 20 wherein the second lock comprises:

an annular lock profile formed in the bore of the skirt and having a low pressure passage in fluid communication with the downhole annulus;

an annular lock groove adjacent the downhole end of the piston and having a high pressure passage in fluid communication with the fluid inlet;

an annular sleeve fit to the annular lock groove and hydraulically actuable between the high and low pressure passages from a radially retracted position to a radially expanded position; and

one or more annular band segments fit to the annular lock groove and having an annular profile formed on an outer surface, the one or more band segments overlying the annular sleeve so that when the tool is in the collapsed drilling position and hydraulically actuated, the sleeve expands and drives the annular profile of the one or more band segments radially outward to radially engage the annular lock profile and axially lock the piston to the skirt.

22. The tool of claim 21 wherein:

the annular lock profile further comprises one or more annular grooves, each of which comprises a downhole conical cam face; and

the band segment annular profile further comprises one or more annular projections, each of which comprises an uphole conical cam face, each corresponding to one of the one of more downhole conical cam faces, and wherein upon a return to the extended position and a failure of the one or more band segments to radially retract, further telescopic movement of the piston into the skirt causes the downhole and uphole cam faces to drive the one or more band segments radially inward to release the second lock.

23. A method for drilling a wellbore comprising:

centralizing a tool body and drill bit in the wellbore for forming an annulus therebetween and being suspended from tubing string extending from surface;

supporting an expandable packer for co-rotation with, and positioned coaxially about, the tool body;

radially expanding the expandable packer to substantially isolate an uphole annulus from a downhole annulus and for forming an internal passageway between the expandable packer and the tool body, the internal passageway extending between the uphole annulus and the downhole annulus adjacent the drill bit;

rotating the tool body for rotating the drill bit and drilling the wellbore; and

circulating fluid through the tool body and through a jet pump located in the tool body for discharging fluid from a jet pump nozzle to the uphole annulus and depressing pressure in a jet pump venturi chamber formed about the nozzle, the venturi chamber being in fluid communication with the internal passageway for depressing the pressure in the downhole annulus and circulating the fluid from the downhole annulus, through the internal passageway to the uphole passageway.

24. The method of claim 23 wherein the expanding of the expandable packer further comprises axially collapsing a piston and a skirt of the tool body.

25. The method of claim 24 further comprising:

forming the expandable packer from a plurality of upper trapezoidal segments spaced circumferentially about the tool body, each upper trapezoidal segment having a wide base which is oriented uphole and a plurality of lower trapezoidal segments spaced circumferentially about the tool body each lower trapezoidal segment having a wide base which is oriented downhole, and wherein each lower trapezoidal segment is spaced from each other lower trapezoidal segment by an upper trapezoidal segment and connected at radial faces for relative sliding axial movement, and

wherein the radial expanding of the expandable packer further comprises

axially sliding the lower and upper trapezoidal segments axially together for forming a cylindrical packer of variable diameter.

26. The method of claim 23 further comprising radially contracting the expandable packer to enable tripping of the tool through the wellbore.

27. The method of claim 26 wherein the radially contracting of the expandable packer further comprises axially extending a piston and a skirt of the tool body.

28. The method of claim 25 further comprising radially contracting the expandable packer by axially sliding the lower and upper trapezoidal segments axially apart to enable tripping of the tool through the wellbore.

29. The method of claim 24 wherein the supporting of the expandable pack for co-rotation further comprises:

providing a spline on at least one of the piston and skirt and providing axially extending slots in the expandable packer corresponding to the spline; and

radially engaging the spline and axial slots for enabling co-rotation while enabling the axial collapsing and an axial extending of the piston and skirt.

30. The method of claim 23 further comprising circulating fluid from the uphole annulus to the drill bit.

31. The method of claim 24, wherein prior to expanding the expandable packer, further comprising overcoming a mechanical lock for enabling collapsing of the piston and skirt.

32. The method of claim 31, wherein during circulating of fluid, further comprising forming a pressure differential between the tool body and the downhole annulus for hydraulically engaging a hydraulic lock between the piston and the skirt for retaining the piston and skirt in the collapsed position.

33. A jet pump for a downhole tool and drill bit suspended in a wellbore on a tubing string comprising:

a tool body and drill bit adapted for receiving a fluid supply from the drill string; and

a jet pump having nozzle in fluid communication with the fluid supply and a venturi about the nozzle in fluid communication with the wellbore adjacent the drill bit, the venturi being eccentric from the nozzle for maximizing the cross-sectional area therethrough for passing debris.