Patent Publication Number: US-2007114063-A1

Title: Mud depression tool and process for drilling

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&#39;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&#39;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&#39;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&#39;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&#39;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&#39;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  15   p  is concentrically positioned about the tool  10  for reversibly and radially engaging the wellbore  11 .  
      Having reference also to  FIG. 3 , the expandable packer  15   p  is concentrically positioned and actuable about a tool body  20  of cylindrical configuration. The expandable packer  15   p  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  15   p  acts as a packer to fluidly separate the annulus  14  into an uphole annulus  14   u  and a downhole annulus  14   d.    
      The actuated expandable packer  15   p  also acts as a robust centralizer  15   c  for the tool  10 .  
      The tool body  20  and packer  15   p  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  14   u  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  14   u  for inducing fluid flow from the drill bit  13  to induce a low pressure in the downhole annulus  14   d  and further to direct drill cuttings (not shown), from the downhole annulus  14   d , to the higher pressure uphole annulus  14   u.    
      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  15   p  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  15   p , skirt  31 , and bit  13  while still enabling relative axial movement. The expandable packer  15   p  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  15   p  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  14   u . In the tripping configuration, the upper inlet  51  can also feed second passageways  53  extending between drill bit  13  and the uphole annulus  14   u . 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  52   a  to a “U” passage  52   b  and back along an uphole portion  52   c  to the jet pump  25  and continuing uphole through a discharge portion  52   d  to the upper annulus  14   u . Each of the downhole through discharge portions  52   a , 52   b , 52   c , 52   d  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  52   a  off-axis slightly to accommodate the “U” passage  52   b  and then directing the uphole and discharge portions  52   d  substantially parallel to the downhole portion  52   a.    
      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  52   b  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  52   b  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  52   b  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  52   b  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  52   b  to the jet pump  25 . An upper surface of plug  63  can matche a contour of the “U” passage  52   b.    
      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  14   u  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  13 A, fluid powering the jet pump  25  flows about the “U” passage  52   b . 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  14   d  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  15   p . Uphole and downstream of the nozzle  80  is a mixing area  84  and a fluid expansion area  87  that channeled fluid through uphole passage  52   d  to the uphole end  3  of piston  30  for discharge to the upper annulus  14   u.    
      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  15   p  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  15   p  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  15   p  work in concert. The expandable packer  15   p  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  14   u  above the packer  15   p  from the downhole annulus  14   d  and bit  13  below the packer  15   p.    
      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  15   p  and tool body  20 . The venturi passageway  86  is in fluid communication between the wellbore  11  below the packer  15   p  and the uphole annulus  14   u  above the packer  15   p . 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  15   p  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  15   p  is axially supported at a downhole end  90  at a conical surface  91  of the blade centralizer  16  for enabling actuation of the packer  15   p  relative to the piston  30  when the piston and skirt  31  are telescoped to the collapsed position. The packer  15   p  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  15   p . The piston  30  further comprises a spline  95  extending along the piston  30  for enabling co-rotation of the expandable packer  15   p  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  15   p , such as through corresponding sockets  101  formed in the packer  15   p  for enabling co-rotation of the piston  30  and the packer  15   p.    
      Best seen in  FIGS. 1 and 2 , the packer  15   p  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  110   b , 111   b , 110   b , 111   b  . . . 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  111   b  located downhole and the upper trapezoidal segments  110  have their bases  110   b  located uphole. Together, the trapezoidal segments  110 , 111  form a tubular, expandable cylindrical packer  15   p  having a central axis which coincides with the axis of the tool body  20 .  
      With reference to  FIGS. 3, 4A  and  4 B, about the entire circumference of the cylindrical packer  15   p , 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  15   p . 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  15   p  and through the expandable packer  15   p  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  15   p  is actuated.  
      As stated earlier, the packer  15   p  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  111   b  to the tool body  20  through angularly oriented, radially extending interlocking guides  120  ( FIGS. 6 and 8 B). 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  15   p  is actuated. Accordingly, torque can be transmitted from the piston&#39;s spline  95  to at least the upper segments  110  of the packer  15   p  and from the packer  15   p  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 ,  8 A and  8 B, 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&#39;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  111   b  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  15   p . Equal numbers of upper and lower trapezoidal segments  110 , 111  are provided.  
      The outer diameter of the packer  15   p  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  15   p  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  15   p  and the skirt  31 . The longitudinal segments  111  of the packer  15   p  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  15   b . Further, the upper stop groove  140  of the packer  15   p  engages the longitudinal stop bars  142  on the piston  30  and thus the packer  15   p  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  15   p  and the spline base  94  of the piston  30  which forms the venturi passageway  86 . The venturi passageway communicates between the annulus  14   d  below the packer  15   p  and the venturi chamber  85  intermediate axially along packer  15   p.    
      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 7 B, 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  170   u  and lower sides  170   d  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  107   u , 170   d  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&#39;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  15   p  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&#39;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&#39;s annular profiles, axially locking the piston  30  and skirt  31 .  
      In greater detail, and with reference to  FIGS. 3, 8A  and  13 B, 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&#39;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  14   d  and the set of annular grooves  182 . The ports  190  preferably extend to the downhole annulus  14   d  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  14   d , 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 7 B, 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  15   p  has a small external diameter similar to that of the upper radial support  93 . The segments  110 , 111  reside between the piston&#39;s uphole end  3  and the blade centralizer  16 . The base of  110   b  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  52   b  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  52   c  and through the expansion area of the uphole portion  52   c  to the uphole annulus  14   u.    
      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  14   d  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 ,  4 A 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&#39;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  110   b  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  111   b  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 5 A).  
      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  52   b  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  14   u  above the now expanded expandable packer  15   p . 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  14   u  located above the expandable packer  15   p  and the downhole annulus  14   d  of the bottom hole. This recirculation circuit forms starting with the high pressure fluid in the annulus  14   u  at the filters  67 . Fluid from the annulus  14   u  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  15   p . 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 8 A) 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  15   p  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  15   p  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  15   p . 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  15   p  comes from the drill string  12  to the piston  30  and to the piston skirt  31  via the expandable packer  15   p . 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  15   p  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  15   p , 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  15   p . 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  15   p  collapses axially. The expandable packer  15   p  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 .