Abstract:
Embodiments of the present invention generally relate to methods and apparatuses for anchoring progressing cavity (PC) pumps. In one embodiment, a method of anchoring a PC pump to a string of tubulars disposed in a wellbore which includes acts of inserting the PC pump and anchor assembly into the tubular. Running the PC pump and anchor assembly through the tubular to any first longitudinal location along the tubular string. Longitudinally and rotationally coupling the PC pump and the anchor assembly to the tubular and forming a seal between the PC pump and the tubular string at the first location and performing a downhole operation in the tubular.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments described herein are directed toward artificial lift systems used to produce fluids from wellbores, such as crude oil and natural gas wells. More particularly, embodiments described herein are directed toward an improved anchor for use with a downhole pump. More particularly, the embodiments described herein are directed to a resettable anchor configured to prevent longitudinal and rotational movement of the pump relative to a tubular. 
     2. Description of the Related Art 
     Modern oil and gas wells are typically drilled with a rotary drill bit and a circulating drilling fluid or “mud” system. The mud system (a) removes drill bit cuttings from the wellbore during drilling, (b) lubricates and cools the rotating drill bit, and (c) provides pressure within the borehole to balance internal pressures of formations penetrated by the borehole. Rotary motion is imparted to the drill bit by rotation of a drill string to which the bit is attached. Alternately, the bit is rotated by a mud motor which is attached to the drill string just above the drill bit. The mud motor is powered by the circulating mud system. Subsequent to the drilling of a well, or alternately at intermediate periods during the drilling process, the borehole is cased typically with steel casing, and the annulus between the borehole and the outer surface of the casing is filled with cement. The casing preserves the integrity of the borehole by preventing collapse or cave-in. The cement annulus hydraulically isolates formation zones penetrated by the borehole that are at different internal formation pressures. 
     Numerous operations occur in the well borehole after casing is “set”. All operations require the insertion of some type of instrumentation or hardware within the borehole. Examples of typical borehole operations include: (a) setting packers and plugs to isolate producing zones; (b) inserting tubing within the casing and extending the tubing to the prospective producing zone; and (c) inserting, operating and removing pumping systems from the borehole. 
     Fluids can be produced from oil and gas wells by utilizing internal pressure within a producing zone to lift the fluid through the well borehole to the surface of the Earth. If internal formation pressure is insufficient, artificial fluid lift devices and methods may be used to transfer fluids from the producing zone and through the borehole to the surface of the Earth. 
     One common artificial lift technology utilized in the domestic oil industry is the sucker rod pumping system. A sucker rod pumping system consists of a pumping unit that converts a rotary motion of a drive motor to a reciprocating motion of an artificial lift pump. A pump unit is connected to a polish rod and a sucker rod “string” which, in turn, operationally connects to a rod pump in the borehole. The string can consist of a group of connected, essentially rigid, steel sucker rod sections (commonly referred to as “joints”) in lengths, such as twenty-five or thirty feet (ft), and in diameters, such as ranging from five-eighths inch (in.) to one and one-quarter in. Joints are sequentially connected or disconnected as the string is inserted or removed from the borehole, respectively. Alternately, a continuous sucker rod (hereafter referred to as COROD) string can be used to operationally connect the pump unit at the surface of the Earth to the rod pump positioned within the borehole. A delivery mechanism rig (hereafter CORIG) is used to convey the COROD string into and out of the borehole. 
     Prior art borehole pump assemblies of sucker rod operated artificial lift systems typically utilize a progressing cavity (PC) pump positioned within wellbore tubing.  FIG. 1A  is a sectional view of a prior art PC pump  100 . A pump housing  110  contains an elastomeric stator  130   a  having multiple lobes  125  formed in an inner surface thereof. The pump housing  110  is usually made from metal, preferably steel. The stator  130   a  has five lobes. Although, the stator  130   a  may have two or more lobes. Inside the stator  130   a  is a rotor  118 . The rotor  118  having one lobe fewer than the stator  130   a  formed in an outer surface thereof. The inner surface of the stator  130   a  and the outer surface of the rotor  118  also twist along respective longitudinal axes, thereby each forming a substantially helical-hypocycloid shape. The rotor  118  is usually made from metal, preferably steel. The rotor  118  and stator  130   a  interengage at the helical lobes to form a plurality of sealing surfaces  160 . Sealed chambers  147  between the rotor  118  and stator  130   a  are also formed. In operation, rotation of the sucker rod or COROD string causes the rotor  118  to nutate or process within the stator  130   a  as a planetary gear would nutate within an internal ring gear, thereby pumping production fluid through the chambers  147 . The centerline of the rotor  118  travels in a circular path around the centerline of the stator  120 . 
     One drawback in such prior art motors is the stress and heat generated by the movement of the rotor  118  within the stator  130   a . There are several mechanisms by which heat is generated. The first is the compression of the elastomeric stator  130   a  by the rotor  118 , known as interference. Radial interference, such as five-thousandths of an inch to thirty-thousandths of an inch, is provided to seal the chambers to prevent leakage. The sliding or rubbing movement of the rotor  118  combined with the forces of interference generates friction. In addition, with each cycle of compression and release of the elastomeric stator  130   a , heat is generated due to internal viscous friction among the elastomer molecules. This phenomenon is known as hysteresis. Cyclic deformation of the elastomer occurs due to three effects: interference, centrifugal force, and reactive forces from pumping. The centrifugal force results from the mass of the rotor moving in the nutational path previously described. Reactive forces from torque generation are similar to those found in gears that are transmitting torque. Additional heat input may also be present from the high temperatures downhole. 
     Because elastomers are poor conductors of heat, the heat from these various sources builds up in the thick sections  135   a - e  of the stator lobes. In these areas the temperature rises higher than the temperature of the circulating fluid or the formation. This increased temperature causes rapid degradation of the elastomeric stator  130   a . Also, the elevated temperature changes the mechanical properties of the elastomeric stator  130   a , weakening each of the stator lobes as a structural member and leading to cracking and tearing of sections  135   a - e , as well as portions  145   a - e  of the elastomer at the lobe crests. This design can also produce uneven rubber strain between the major and minor diameters of the pumping section. The flexing of the lobes  125  also limits the pressure capability of each stage of the pumping section by allowing more fluid slippage from one stage to the subsequent stages below. 
     Advances in manufacturing techniques have led to the introduction of even wall PC pumps  150  as shown in  FIG. 1B . A thin tubular elastomer layer  170  is bonded to an inner surface of the stator  130   b  or an outer surface of the rotor  118  (layer  170  bonded on stator  130   b  as shown). The stator  130   b  is typically made from metal, preferably steel. These pumps  150  provide more power output than the traditional designs above due to the more rigid structure and the ability to transfer heat away from the elastomer  170  to the stator  130   b . With improved heat transfer and a more rigid structure, the new even wall designs operate more efficiently and can tolerate higher environmental extremes. Although the outer surface of the stator  130   b  is shown as round, the outer surface may also resemble the inner surface of the stator. Further, the rotor  118  may be hollow. 
       FIG. 2  illustrates a prior art insertable PC pump assembly  200 . The PC pump assembly  200  includes a rotor sub-assembly, a stator sub-assembly, and a special production tubing sub-assembly. The special production tubing sub-assembly is assembled and run-in with the production tubing. The production tubing sub-assembly includes a pump seating nipple  236 , a collar  238 , and a locking tubing joint  240 . The pump seating nipple  236  is connected to the collar  238  by a threaded connection. The nipple  236  includes a profile formed on an inner surface thereof for seating a profile formed on an outer surface of a seating mandrel  220 . The collar  238  is connected to the locking tubing  240  by a threaded connection. The locking tubing joint  240  includes a pin  242  protruding into the interior thereof. The pin  242  will receive a fork  234  of a tag bar  232 , thereby forming a rotational connection. Before the PC pump assembly  200  is positioned and operated down hole, the special production tubing sub-assembly is installed as part of the production tubing string so that the pump will be positioned to lift from a particular producing zone of interest. If the PC pump assembly  200  is subsequently positioned at a shallower or at a deeper zone of interest within the well, this can be accomplished by removing the tubing string, or by adding or subtracting joints of tubing. This repositions the special joint of tubing as required. 
     The rotor sub-assembly includes a pony rod  212 , a rod coupling  216 , and a rotor  218 . The top of the pony rod  212  is connected to a COROD string (not shown) or to a conventional sucker rod string (not shown) by the connector  214 , thereby forming a threaded connection. The pony rod  212  is connected to the top of the rotor  218  by the rod coupling  216 , thereby forming a threaded connection. The rotor  218  may resemble the rotor  118 . An outer surface of the rod coupling  216  is configured to abut an inner surface of the cloverleaf insert  222 , thereby longitudinally coupling the cloverleaf insert  222  and the rod coupling  216  in one direction. The rotor  218  is connected to the rod coupling  216  with a threaded connection. 
     The stator sub-assembly includes a seating mandrel  220 , a cloverleaf insert  222 , upper and lower flush tubes  224 , 226 , a barrel connector  228 , a stator  230 , and the tag bar  232 . The seating mandrel  220  is coupled to the upper flush tube  224  by a threaded connection and includes the profile formed on the outer surface thereof for seating in the nipple  236 . The profile is formed by disposing elastomer sealing rings around the seating mandrel  220 . The cloverleaf insert  222  is disposed in a bore defined by the seating mandrel  220  and the upper flush tube  224  and longitudinally held in place between a shoulder formed in each of the seating mandrel  220  and the upper flush tube  224 . The inner surface of the cloverleaf insert  222  is configured to shoulder against the outer surface of the rod coupling  216 . The lower flush tube  226  is coupled to the upper flush tube  224  by a threaded connection. Alternatively, the flush tube  224 , 226  may be formed as one integral piece. The barrel connector  228  is coupled to the lower flush tube  226  by a threaded connection. The stator  230  is coupled to the barrel connector  228  by a threaded connection. The stator  230  may be either the conventional stator  130   a  or the recently developed even-walled stator  130   b . The tag bar  232  is connected to the stator  230  with a threaded connection. A fork  234  is formed at a longitudinal end of the tag bar  232  for mating with the pin  242 , thereby forming a rotational connection between the tag bar  232  and the locking tubing  240 . The tag bar  232  further includes a tag bar pin  235  (see  FIG. 3 ) for seating a longitudinal end of the rotor  218 . 
       FIG. 3A  illustrates the rotor and stator sub-assemblies of the prior art PC pump assembly  200  being inserted into a borehole. The production tubing sub-assembly is installed as part of the production tubing string so that the PC pump assembly  200 , when installed downhole, will be positioned to lift from a particular producing zone of interest. Once the production tubing sub-assembly is installed down hole as part of the tubing string, the rotor and stator sub-assemblies are assembled and run down hole inside of the production tubing using a COROD or conventional sucker rod system. 
       FIG. 3B  illustrates the rotor and stator sub-assemblies being seated within the borehole. When reaching the special locking joint  240 , the forked slot  234  at the lower end of the assembly tag bar  232  aligns with the pin  242  as shown in  FIG. 3B . Once the fork slot  234  aligns with and engages the pin  242 , the stator sub-assembly is locked radially within the locking joint  240  and can not rotate within the locking joint  240  when the PC pump assembly  200  is operated. After the fork  234  and pin  242  have aligned and engaged, the seating mandrel  220  will then slide into, seat with, and form a seal with the seating nipple  236 . The prior art insertable PC pump assembly  200  is now completely installed down hole. 
       FIG. 3C  illustrates the prior art PC pump assembly  200  in operation, where the rotor  218  is moved up and down within the stator  230  by the action of the pony rod  212  and connected sucker rod string (not shown). After compensating for sucker rod stretch, the sucker rod string is slowly lifted a distance  252 , off of the tag bar pin  235  of the tag bar  232 . This positions the rotor  218  in a proper operating position with respect to the stator  230 . 
       FIG. 3D  shows the system configured for flushing. During operation, it is possible that the insertable PC pump assembly  200  may need to be flushed to remove sand and other debris from the stator  230  and the rotor  218 . To perform this flushing operation, the rotor  218  is pulled upward from the stator by the sucker rod string by a distance  254 . In order to avoid disengaging the entire pump assembly  200  from the seating nipple  236 , the rotor  218  is moved upward only until it is located in the flush tubes  224 ,  226 . The PC pump assembly  200  may now be flushed, and then the rotor  218  reinstalled without completely reseating the entire PC pump assembly  200 . Since the prior art insertable PC pump assembly  200  is picked up from the top of the rotor  218 , the flush tubes  224 ,  226  are required. Furthermore, the length of the flush tubes  224 ,  226  must be at least as long as the rotor  218 . The entire PC pump assembly  200  will then be at least twice as long as the stator  230 . This presents a problem in optimizing stator length within the operation and clearly illustrates a major deficiency in prior art insertable PC pump systems. 
       FIG. 3E  illustrates the rotor and stator sub-assemblies being removed from the locking joint  240  and seating nipple  236 . The sucker rod string is lifted until the rod coupling  216  on the top of the rotor  218  engages with the cloverleaf insert  222 . The seating mandrel  220  is then extracted from the seating nipple  236  by further upward movement of the sucker rod string, and the rotor and stator subassemblies are conveyed to the surface as the sucker rod string is withdrawn from the borehole. 
     The operating envelope of an insertable PC pump is dependent upon pump length, pump outside diameter, and the rotational operating speed. In the prior art PC pump assembly  200 , the pump length is essentially fixed by the distance between the seating nipple  236  and the pin  242  of the locking joint  240 . Pump diameter is essentially fixed by the seating nipple size. Stated another way, these factors define the operating envelope of the pump. For a given operating speed, production volume can be gained by lengthening stator pitch and decreasing the total number of pitches inside the fixed operating envelope. Volume is gained at the expense of decreasing lift capacity. On the other hand, lift capacity can be gained within the fixed operating envelope by shortening stator pitch and increasing the total number of pitches. Production volume can only be gained, at a given lift capacity, by increasing operating speed. This in turn increases pump wear and decreases pump life. For a given operating speed and a given seating nipple size, the operating envelope of the prior art system can only be changed by pulling the entire tubing string and adjusting the operating envelope by changing the distance between the seating nipple  236  and the pin  242 . Alternately, the tubing can be pulled and the seating nipple  236  can be changed thereby allowing the operating envelope to be changed by varying pump diameter. Either approach requires that the production tubing string be pulled at significant monetary and operating expense. 
     In summary, the prior art insertable PC pump system described above requires a special joint of tubing containing a welded, inwardly protruding pin for radial locking and a seating nipple. The seating nipple places some restrictions upon the inside diameter of the tubing in which the pump assembly can be operated. This directly constrains the outside diameter of the insertable pump assembly. The overall distance between the pin and the seating nipple constrains the length of the pump assembly. In order to change the length of the pump assembly to increase lift capacity (by adding stator pitches) or to change production volume (by lengthening stator pitches), (1) the entire tubing string must be removed and (2) the distance between the seating nipple  236  and the locking pin  242  must be adjusted accordingly before the production tubing is reinserted into the well. Longitudinal repositioning of the PC pump assembly  200  without changing length can be done by adding or subtracting tubing joints to reposition the seating nipple  236  and the locking pin  242  as a unit. The prior art PC pump assembly  200  requires a flush tube  224 , 226  so that the rotor  218  can be removed from the stator  230  for flushing. This increases the length of the assembly and also adds to the mechanical complexity and the manufacturing cost of the assembly. 
     Therefore, there exists a need in the art for an insertable PC pump that does not require specialized components to be assembled with a production string. 
     SUMMARY OF THE INVENTION 
     Embodiments described herein generally relate to a method of anchoring a PC pump in a tubular located in a wellbore. The method comprises running the PC pump coupled to an anchor assembly to a first longitudinal location inside the tubular and actuating the anchor assembly thereby engaging the tubular with an anchor of the anchor assembly. The engaging of the tubular thereby preventing the rotation and longitudinal movement of the anchor assembly relative to the tubular. The method further comprises setting off a relief valve in the anchor assembly thereby releasing the anchor assembly from the tubular. 
     Embodiments described herein further relate to an anchoring assembly for anchoring a downhole tool in a tubular in a wellbore. The anchoring assembly comprises an inner mandrel, and an anchor actuable by the manipulation of the inner mandrel. The anchoring assembly further comprises an engagement member configured to engage an inner wall of the tubular and resist longitudinal forces applied to the anchoring assembly. The anchoring assembly further comprises an actuation assembly having one or more one way valves configured to allow fluid to flow from a first piston chamber to a second piston chamber and a relief valve configured to release fluid pressure in the second piston chamber, wherein the relief valve allows the release of the anchor when a predetermined fluid pressure is applied to the second piston chamber. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1A  is a sectional view of a prior art progressing cavity (PC) pump.  FIG. 1B  is a sectional view of a prior art even wall PC pump. 
         FIG. 2  illustrates a prior art insertable PC pump system. 
         FIG. 3A  illustrates rotor and stator sub-assemblies of a prior art PC pump system being inserted into a borehole.  FIG. 3B  illustrates the rotor and stator sub-assemblies being seated within the borehole.  FIG. 3C  illustrates the prior art PC pump system being operated within the borehole.  FIG. 3D  illustrates the prior art PC pump system being flushed.  FIG. 3E  illustrates the rotor and stator sub-assemblies being removed from the borehole. 
         FIG. 4A  is an isometric sectional view of a PC pump assembly, according to one embodiment of the present invention.  FIG. 4B  is a partial half-sectional view of an anchor of the PC pump system of  FIG. 4A .  FIG. 4C  is a schematic showing various operational positions of a J-pin and slotted path of the PC pump system of  FIG. 4A .  FIG. 4D  is a sectional view taken along lines  4 D- 4 D of  FIG. 4B . 
         FIGS. 5A-G  illustrate various positions of the PC pump system of  FIG. 4A .  FIG. 5A  illustrates the PC pump system being run-into a wellbore.  FIG. 5B  illustrates the PC pump system in a preset position.  FIG. 5C  illustrates the PC pump system in a set position.  FIG. 5D  illustrates the PC pump system in a pre-operational position.  FIG. 5E  illustrates the PC pump system in an operational position.  FIG. 5F  illustrates the improved PC pump system in a flushing position.  FIG. 5G  illustrates the improved PC pump system being removed from the borehole. 
         FIG. 6  is a cross sectional view of an anchor assembly according to one embodiment described herein. 
         FIG. 7A  is a side view of an anchor assembly according to one embodiment described herein. 
         FIG. 7B  is a detail of a slotted path according to one embodiment described herein. 
         FIG. 8  is a cross sectional view of a valve assembly according to one embodiment described herein. 
         FIGS. 9A and 9B  are cross sectional views of a sealing member for the valve assembly according to one embodiment described herein. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 4A  is an isometric sectional view of a PC pump assembly  400 , according to one embodiment of the present invention. Unlike the prior art PC pump assembly  200 , the PC pump assembly  400  does not require a special production tubing sub-assembly. In other words, the PC pump assembly  400  is capable of longitudinal and rotational coupling to an inner surface of a conventional production tubing string at any longitudinal location along the production tubing string. This feature allows for installation of the PC pump assembly  400  at a first longitudinal location or depth along the production tubing string, operation of the PC pump assembly  400 , and relocation of the PC pump assembly to a second longitudinal location or depth along the production tubing string, which may be closer or farther from the surface relative to the first location, without pulling and reconfiguration of the production tubing string. The PC pump assembly  400  includes a rotor subassembly, a stator subassembly, and an anchor subassembly  450 . Unless otherwise specified, components of the PC pump assembly  400  are made from metal, such as steel or stainless steel. 
     The rotor subassembly includes a pony rod  412 , a rotor  418 , and a wedge-shaped structure or arrowhead  419 . The pony rod  412  includes a threaded connector at a first longitudinal end for connection with a drive string, such as a conventional sucker rod string, a COROD string, a wireline, a coiled tubing string, or a string of jointed (i.e., threaded joints) tubulars. A wireline may be used for instances where the PC pump assembly  400  is driven by an electric submersible pump (ESP). The coiled tubing string may be used for instances where the PC pump is driven by a downhole hydraulic motor. The pony rod  412  may connect at a second longitudinal end to a first longitudinal end of the rotor  418  by a threaded connection. The rotor  418  may resemble the rotor  118 . The arrowhead  419  may connect to a second longitudinal end of the rotor by a threaded connection. The wedge-shaped outer surface of the arrowhead  419  facilitates insertion and removal of the rotor  418  through the stator  430 . The outer surface of the arrowhead  419  is also configured to interfere with an inner surface of the floating ring  422  to provide longitudinal coupling therebetween in one direction. Alternatively, any type of no-go device, such as one similar to the rod coupling  216 , may be used instead of the arrowhead  419 . 
     The stator subassembly includes an optional seating mandrel  420 , a floating ring  422 , an optional ring housing  424 , a flush tube  426 , a barrel connector  428 , a stator  430 , and a tag bar  432 . The seating mandrel  420 , the floating ring  422 , the ring housing  424 , the flush tube  426 , the barrel connector  428 , and the tag bar  432  are tubular members each having a central longitudinal bore therethrough. The seating mandrel  420  is coupled to the upper flush tube  426  by a threaded connection and includes an optional profile formed on the outer surface thereof for seating in the nipple  236 . The profile may be provided in cases where the nipple  236  has already been installed in the production tubing. The profile is formed by disposing one or more sealing rings  421  around the seating mandrel  420 . The sealing rings  421  are longitudinally coupled to the seating mandrel  420  at a first end by a shoulder formed in an outer surface of the seating mandrel  420  and at a second end by abutment with a first longitudinal end of a gage ring  423 . The gage ring  423  has a threaded inner surface and is disposed on a threaded end of the seating mandrel  420 . 
     The ring housing  424  has a threaded inner surface at a first longitudinal end and is disposed on the threaded end of the seating mandrel  420 . The first longitudinal end of the ring housing  424  abuts a second longitudinal end of the gage ring  423  and is connected to the threaded end of the seating mandrel  420  with a threaded connection. The threaded end of the seating mandrel  420  has an o-ring and a back-up ring disposed therein (in an unthreaded portion). An inner surface of the ring housing  424  forms a shoulder and the floating ring  422  is disposed, with some clearance, between the shoulder of the ring housing  424  and the threaded end of the seating mandrel  420 , thereby allowing limited longitudinal movement of the floating ring  422 . Clearance is also provided between an outer surface of the floating ring  422  and the inner surface of the ring housing  424 , thereby allowing limited radial movement of the floating ring  422 . The inner surface of the floating ring  422  is configured to interfere with the outer surface of the arrowhead  419 , thereby providing longitudinal coupling therebetween in one direction. Preferably, this configuration is accomplished by ensuring that a minimum inner diameter of the floating ring  422  is less than a maximum outer diameter of the arrowhead  419 . The floating action of the floating ring  422 , provided by the longitudinal and radial clearances, allows the rotor  418  to travel therethrough. Alternatively, any no-go ring, such as the cloverleaf insert  222 , may be used instead of the floating ring  422 . 
     The flush tube  426  is coupled to the ring housing  424  by a threaded connection. Alternatively, the flush tube  426  and the ring housing  424  may be formed as one integral piece. The barrel connector  428  is coupled to the flush tube  426  by a threaded connection. The stator  430  is coupled to the barrel connector  428  by a threaded connection. The stator  430  may be either the conventional stator  130   a  or the recently developed even-walled stator  130   b . The tag bar  432  is connected to the stator  430  with a threaded connection. The tag bar  432  includes a tag bar pin  435  for seating the arrowhead  419 . A cap  452  (see  FIG. 4B ) of the anchor subassembly  450  is connected to the tag bar  432  with a threaded connection. 
       FIG. 4B  is a partial half-sectional view of the anchor subassembly  450  of the PC pump assembly  400 . The anchor includes the cap  452 , a J-mandrel  454 , a sealing element  458 , a slip mandrel  460 , and a J-runner/slip retainer  468 . The J-runner  468  includes two or more slips  464 , two or more cantilever springs  466 , upper  468   a  and lower  468   c  spring retainers, a J-pin retainer  468   b , two or more bow springs  472 , and a J-pin  470 . 
     The cap  452 , the gage ring  456 , the sealing element  458 , the slip mandrel  460 , and the J-mandrel  454  are tubular members each having a central longitudinal bore therethrough. The cap  452  is connected to the J-mandrel  454  with a threaded connection. A longitudinal end of the cap  452  forms a tapered shoulder which abuts a tapered shoulder formed at a first longitudinal end of a gage ring  456 . The gage ring  456  has a threaded inner surface which engages a threaded portion of an outer surface of the J-mandrel  454 . The gage ring  456  may be made from metal or a hard plastic, such as PEEK. The gage ring  456  also has a curved shoulder formed at a second longitudinal end which abuts a curved shoulder formed at a first longitudinal end of the sealing element  458 . Preferably, a portion of an inner surface of the sealing element  458  is bonded to an outer surface of the gage ring  456 . The remaining portion of the inner surface of the sealing element  458  is disposed along the outer surface of the J-mandrel  454 . The sealing element  458  is made from a polymer, preferably an elastomer. Alternatively, the sealing element  458  may be made from a urethane (urethane may or may not be considered an elastomer depending on the degree of cross-linking). During setting of the slips  464 , the sealing element  458  is longitudinally compressed between the gage ring  456  and the slip mandrel  460  in order to radially expand into sealing engagement with the production tubing  500  (see  FIG. 5 ). The sealing element  458  has a shoulder formed at a second longitudinal end which abuts a shoulder formed at a first longitudinal end of the slip mandrel  460 . 
     The slip mandrel  460  may include a base portion  460   a  and a plurality of finger portions  460   b  longitudinally extending from the base portion. A flat actuations surface  460   c  is formed in a portion of an outer surface of each of the finger portions  460   b . Two adjacent flat surfaces cooperatively engage to form an actuation surface  460   c  for each of the slips  464 . The discontinuity between the flat surfaces  460   c  and the remaining tubular outer surfaces of the finger portions  460   b , when engaged with corresponding inner surfaces of the slips  464 , provides rotational coupling between the slips  464  and the slip mandrel  460 . Referring to  FIG. 4D , rotational coupling between the slip mandrel  460  and the J-mandrel  454  is provided by a key  461  disposed in a slot formed in the outer surface of the J-mandrel  454  and a corresponding slot formed in an inner surface of the slip mandrel  460 . Returning to  FIG. 4B , the outer surface of the finger portions  460   b  is inclined at a second longitudinal end of the slip mandrel  460 . The second longitudinal end of the slip mandrel  460  abuts a slip mandrel retainer  462 . The slip mandrel retainer  462  abuts a shoulder formed in the outer surface of the J-mandrel  454 . Attached to a second longitudinal end of the J-mandrel  454  by a threaded connection is an optional thread adapter  474 . The thread adapter allows other tools (not shown) to be attached to the J-mandrel  454  if desired. 
     Referring also to  FIG. 4C , the J-runner  468  is disposed along the outer surface of the J-mandrel  454 . The J-runner  468  includes the J-pin  470  which extends into a slotted path  454   j,r,s  formed in the outer surface of the J-mandrel  454 . Alternatively, the slotted path  454   j,r,s  may be formed in an inner surface of the J-mandrel  454  or through the J-mandrel  454 . The slotted path  454   j,r,s  may include three portions: a J-slot portion  454   j  formed proximate to a second longitudinal end of the J-mandrel  454 , a first longitudinal or setting portion  454   s  extending from the J-slot  454   j  toward a first longitudinal end of the J-mandrel  454 , and a second longitudinal or run-in portion  454   r  extending from the J-slot  454   j  toward the first longitudinal end of the J-mandrel  454 . The slotted path  454   j,r,s  includes one or more ends or pockets at which the J-pin  470  is longitudinally coupled to the J-mandrel in one direction. Movement of the J-mandrel  454  in the opposite direction will move the J-pin to the next pocket (with the exception of the setting portion  454   s  which may not have a pocket). Inclined faces formed in the outer surface of the J-mandrel  454  bounding the slotted path  454   j,r,s  guide the J-pin  470  to a particular pocket in a particular sequence. Each of the pockets correspond to one or more operating positions of the anchor  450 : a make-up position MUP, a run-in position RIP, a preset position PSP, a setting position SP, and a pull out of hole position POOH. Reference is made to movement of the J-mandrel  454  instead of movement of the J-runner  468  because, for the most part, the J-runner  468  will be held stationary by engagement of the bow springs  472  with the production tubing  500 . 
     The J-pin  470  is disposed through an opening through a wall of the J-pin retainer  468   b  and attached thereto with a fastener. The spring retainers  468   a,c  and J-pin retainer  468   b  are tubular members each having a central longitudinal bore therethrough. The J-pin retainer  468   b  is disposed longitudinally between the spring retainers  468   a,c  with some clearance to allow for rotation of the J-pin retainer  468   b  relative to the spring retainers  468   a,c . A retainer pin  473  is attached to the upper spring retainer  468   a  with a fastener and radially extends into the first longitudinal portion  454   s , thereby rotationally coupling the upper spring retainer  468   a  to the J-mandrel  454  and maintaining rotational alignment of the slips  464  with the actuation surfaces  460   c . Unlike the J-pin  470 , the retainer pin  473  preferably remains in the first longitudinal setting portion  454   s  of the slotted path  454   j,r,s  during actuation of the anchor  450  through the various positions. Alternatively, the J-pin retainer  468   b  and the upper spring retainer  468   a  may be configured for the alternative where the slotted path  454   j,r,s  is formed on an inner surface of the J-mandrel  454  or therethrough. Attached to the upper  468   a  and lower  468   c  spring retainers with fasteners are two or more bow springs  472 . As discussed above, the bow springs  472  are configured to compress radially inward when the anchor  450  is inserted into the production tubing  500 , thereby frictionally engaging an inner surface of the production tubing  500  to support the weight of the J-runner  468 . Alternatively, the bow springs  472  may be replaced by longitudinal spring-loaded drag blocks. 
     Also attached to the upper spring retainer  468   a  by fasteners are two or more cantilever springs  466 . Attached to each of the cantilever springs  466  by fasteners is a slip  464 . The cantilever springs  466  longitudinally couple the slips  464  to the J-runner  468  while allowing limited radial movement of the slips so that the slips may be set. Alternatively, the slips  464  may be pivotally coupled to the upper spring retainer  468   a  instead of using the cantilever springs  466 . The slips  464  are tubular segments having circumferentially flat inner surfaces and arcuate outer surfaces. As discussed above, the flat inner surfaces of the slips  464  engage with the actuation surfaces  460   c  of the slip mandrel  460  to form a rotational coupling. Alternatively, the rotational coupling between the inner surfaces of the slips  464  and the actuation surfaces  460   c  of the slip mandrel  460  may be provided by straight splines, convex-concave surfaces, or key-keyways. Disposed on the outer surfaces of the slips  464  are teeth or wickers made from a hard material, such as tungsten carbide. When set, the teeth penetrate an inner surface of the production tubing  500  to longitudinally and rotationally couple the slips  464  to the production tubing  500 . The teeth may be disposed on the slips  464  as inserts by welding or by weld deposition. Each slip  464  is longitudinally inclined so that when the slip is slid along the actuation surface  460   c  of the slip mandrel  460 , the teeth of the slip  464  will be wedged into the inner surface of the production tubing  500 . 
       FIG. 5A  illustrates the PC pump assembly  400  being run-into a wellbore. Referring also to  FIG. 4C , at the surface, when the PC pump assembly  400  is being assembled or made-up, the J-pin  470  is in the make-up position MUP. The PC pump assembly  400  is then inserted into the production tubing  500 . Alternatively, the anchor  450  may be configured to secure the PC pump assembly  400  to casing of a wellbore that does not have production tubing installed therein, or any other tubular located in a wellbore. The bow springs  472  engage the inner surface of the production tubing  500  and longitudinally and rotationally restrain the J-runner  468  (only longitudinally restrain the J-pin retainer  468   b ). The arrowhead  419  is engaged with the floating ring  422 , thereby supporting the weight of the stator subassembly. The drive string is then lowered into the wellbore. The J-mandrel  454  moves down while the J-runner  468  is stationary. The J-pin  470  contacts the inclined boundary of the J-slot  454   j  at which point the J-pin retainer  468   b  will rotate until the J-pin  470  is longitudinally aligned with the run-in portion  454   r  of the slotted path  454   j,r,s . The J-mandrel  454  continues to move down the wellbore. The run-in pocket RIP reaches the J-pin  470 . The J-mandrel  454  then exerts a downward force on the J-runner  468  via the J-pin  470  which overcomes the frictional restraining force exerted by the bow springs  472 . The J-runner  468  then begins to slide down the production tubing  500  with the stator subassembly and the rest of the anchor subassembly  450 . 
       FIG. 5B  illustrates the improved PC pump system in a preset position. Once the PC pump assembly  400  is lowered to the desired setting depth, the drive string is raised. The J-mandrel  454  moves upward while the J-runner  468  remains stationary. The J-pin  470  contacts another inclined boundary and rotates the J-pin retainer  468   b  until the preset pocket PSP engages the J-pin  470 . 
       FIG. 5C  illustrates the PC pump assembly  400  in a set position. The drive string is then lowered. The J-slot  454   j  travels downward and then the J-pin  470  contacts another inclined boundary and rotates the J-pin retainer  468   b  until the J-pin  470  is longitudinally aligned with the setting portion  454   s  of the slotted path  454   j,r,s . The setting portion  454   s  moves downward until the slips  464  engage the actuation surfaces  460   c . The slips  464  are moved radially outward into engagement with the production tubing  500  by engagement with the actuation surfaces  460   c . The slip mandrel  460  is held stationary by engagement with the slips  464  and the J-mandrel  454  continues a downward movement. The gage ring  456  compresses the sealing element  458  against the stationary slip mandrel  460 . The sealing element  458  radially expands into engagement with the production tubing  500 . At this point, the anchor  450  is set, thereby longitudinally and rotationally coupling the stator subassembly to the production tubing  500 . 
       FIG. 5D  illustrates the PC pump system in a pre-operational position. The drive string continues to be lowered. The arrowhead  419  unseats from the floating ring  422  and the rotor subassembly moves downward. The floating ring  422  floats as the rotor  418  moves through the floating ring  422 . The rotor subassembly is lowered until the arrowhead  419  rests on the tag bar pin  435 . 
       FIG. 5E  illustrates the PC pump assembly  400  in an operational position. After compensating for rod stretch, the drive string is slowly lifted until the arrowhead  419  is at a predetermined distance  505 , for example about 1 foot, above the tag bar pin  435 . The PC pump assembly  400  is now in the operational position and pumping of production fluid from the wellbore to the surface may commence. 
       FIG. 5F  illustrates the PC pump assembly  400  in a flushing position. The rotor  418  is lifted by a second predetermined distance  510 , for example, the length of the rotor  418 . Preferably, the second distance  510  should be sufficient so that the rotor  418  is lifted out of the stator  430  and less than that which would cause the arrowhead  419  to engage with the floating ring  422 . The rotor  418  and the stator  430  may now be flushed of debris. 
       FIG. 5G  illustrates the PC pump assembly  400  being removed from the wellbore. The drive string is lifted so that the arrowhead  419  engages with the floating ring  422 . Lifting is continued. The gage ring  456  moves upward allowing the sealing element  458  to longitudinally expand and disengage from the production tubing  500 . The slip mandrel retainer  462  engages the slip mandrel  460  and pushes the slip mandrel upward with the J-mandrel  454 , thereby disengaging the actuating surfaces  460   c  from the slips  464 . The cantilever springs  466  push the slips  464  radially inward to disengage the slips  464  from the production tubing  500 . The setting portion  454   s  of the slotted path  454   j,r,s  moves upward relative to the stationary J-runner  468 . The J-pin  470  then engages an inclined boundary and rotates the J-pin retainer  468   b  until the J-pin  470  is aligned and seats in the pull out of hole pocket POOH. The J-mandrel  454  exerts an upward force on the J-runner  468  which overcomes the frictional force of the bow springs  472 . The J-runner  468  then slides up the production tubing  500  with the stator subassembly. The PC pump assembly  400  may be raised to the surface where it may be serviced and/or replaced. Alternatively, and as discussed above, the PC pump assembly  400  may be raised or lowered to a second location along the production tubing  500 , re-installed, and further operated. 
       FIG. 6  shows an anchor assembly  600  for anchoring downhole tools to a tubular, in the wellbore according to an alternative embodiment. The anchor assembly  600  comprises a cap  602 , an inner mandrel  604 , a sealing element  606 , an anchor  608 , an engagement member  610 , an actuation assembly  612 , and an outer mandrel  614 . The actuation assembly  612  is adapted to selectively set and release the anchor  608  thereby engaging and disengaging the anchor assembly  600  with the tubular in a wellbore, as will be described in more detail below. The anchor assembly  600  may be coupled to any downhole tool including, but not limited to, any of the pumps described herein, packers, acidizing tools, whipstocks, whipstock packers, production packers and bridge plugs. Further, the anchor assembly  600  may be run into a tubular on any conveyance (not shown) including, but not limited to, a wire line, a slick line, a coiled tubing, a corod, a jointed tubular, or any conveyance described herein. 
     The anchor assembly  600  may include the cap  602  configured to couple the anchor assembly  600  to a downhole tool and/or a conveyance, not shown. The cap  602 , as shown, includes a threaded male end adapted to couple to a female end of the downhole tool and/or conveyance. It should be appreciated that any connection may be used so long as the cap  602  is capable of coupling to the downhole tool and/or conveyance. The cap  602  is coupled to the inner mandrel  604  with a threaded connection thereby preventing relative movement between the cap  602  and the inner mandrel  604  during operation of the anchor  608 . The cap  602  may have a lower shoulder  616  adapted to engage a gage ring  618  during the actuation of the anchor assembly, as will be discussed in more detail below. 
     The inner mandrel  604  is configured to move relative to the engagement member  610 , and the outer mandrel  614  in order to set and release the anchor  608 , as will be described in more detail below. As shown in  FIGS. 7A and 7B , the inner mandrel  604  includes a slotted path  700 . The slotted path  700  may be adapted to engage and manipulate a J-pin  620  in order to set and release the anchor  608 . The inner mandrel  604  supports the sealing element  606 , the anchor  608 , the engagement member  610 , and the actuation assembly  612 . The inner mandrel  604  is manipulated by the conveyance, not shown, in order to operate the anchor  608  and the sealing element  606 . 
     The engagement member  610  may be any member adapted to engage the inner wall of a tubular, not shown, that the anchor assembly  600  is operating in. The engagement member  610 , as shown, is two or more bow springs  626 . The bow springs  626  are configured to compress radially inward when the anchor assembly  600  is inserted into the tubular, thereby frictionally engaging an inner surface of the tubular. The engagement member  610  is adapted to engage the inner wall of the tubular with enough force to prevent the engagement member from moving relative to the inner mandrel  604  during setting and unsetting operations of the anchor assembly  600 . The engagement member  610 , however, does not provide enough force to prevent the anchor assembly  600  from moving in the tubular during run, run out, and relocation in the tubular. The two or more bow springs  626  may be coupled on each end by an upper  628   a  and a lower  628   b  spring retainer. Further, the two or more bow springs  626  couple to the J-pin  620 , via the J-pin retainer  630 . The upper spring retainer  628   a  engages a lower end of the actuation assembly  612 . This enables the engagement member  610  to manipulate the actuation assembly  612 . The actuation assembly in turn operates the anchor assembly  600  as the inner mandrel  604  manipulates the J-pin  620  in the slotted path  700 . 
       FIG. 7B  shows the slotted path  700  with the J-pin  620  in the run in position. The operation of the J-pin  620  in the slotted path may be the same as described above. As the anchoring assembly  600  is being run in, or moved in the tubular, the J-pin  620  is in the run in position. The J-pin  620  remains in the run-in position as a downward force, such as gravity or force from the conveyance, is applied to the inner mandrel  604  in order to move the anchoring assembly  600  down the tubular. In the run in position the J-pin  620  is against an upper end of the slotted path  700  thereby preventing relative movement between the inner mandrel  604  and the engagement member  610 . Once the anchoring assembly  600  arrives at a desired setting position, the inner mandrel  604  is lifted up from the surface of the wellbore. As the inner mandrel  604  moves up, the engagement member  610  holds the J-pin  620  stationary due to the friction force between the two or more bow springs  626  and the tubular. The continued upward movement of the inner mandrel  604  and the slotted path  700  move the J-pin  620  into the preset position PSP. With the J-pin  620  in the preset position PSP, further upward pulling on the inner mandrel  604  causes the entire anchoring assembly  600 , including the engagement member  610 , to move up due to the J-pin being engaged with the lower end of the slotted path  700 . Thus, the upward movement of the inner mandrel  604  is typically stopped once the J-pin is in the preset position PSP. 
     The inner mandrel  604  may then be released or forced down from the surface. As the inner mandrel  604  moves down the engagement member  610  maintains the J-pin  620  stationary in the same manner as described above. As the inner mandrel  604  moves down relative to the J-pin  620 , the J-pin moves to the set position SP. The movement of the J-pin  620  between the preset position PSP and the set position SP causes the anchor assembly to set as will be described in more detail below. The J-pin will remain in the set position SP until it is desired to relocate the anchor assembly  600 . To release the anchor assembly  600 , the inner mandrel  604  is pulled up from the surface until a predetermined force is reached in the actuation assembly  612 . Once the predetermined force is reached, further pulling on the mandrel causes the J-pin  620  to move from the set position to the pull out of hole POOH position. In the pull out of hole POOH position, the J-pin  620  prevents relative movement between the engagement member  610  and the inner mandrel  604  with continued upward pulling on the inner mandrel  604 . If desired, the inner mandrel  604  may be released and the J-pin  620  is allowed to move back to the run in position RIP in order to move the anchoring assembly down and/or reset the anchoring assembly in the tubular without the need to remove the anchoring assembly from the tubular. In one embodiment, the predetermined force is greater than 5000 pounds of tensile force in the inner mandrel  604 . Although the predetermined force is described as being greater than 5000 pounds, it should be appreciated that the predetermined force may be set to any number, and may be as low as 100 lbs and as high as 50,000 lbs. 
     The sealing element  606  and the anchor  608  are set in a similar manner as described above. As the inner mandrel  604  moves down, the engagement member  610  maintains the outer mandrel  614  in a stationary position. The inner mandrel  604  moves the cap  602  against the gage ring  618  which in turn puts a force on the sealing element  606  and a floating slip block  642 . As the floating slip block  642  moves down, it engages one or more slips  644  and forces the one or more slips  644  radially outward. The one or more slips  644  continue to move outward between the floating slip block  648  and a stationary slip block  646 . The stationary slip block  646  may be coupled to the outer mandrel  614  and in turn the engagement member  610  thereby ensuring that the stationary slip block  646  remains stationary relative to the inner mandrel  604  and the floating slip block  642  as the J-pin  620  travels between the preset position PSP and the set position SP. When the J-pin  620  reaches the set position SP, the slips  644  are immovably fixed to the inner wall of the tubular as described above. Further, the sealing element  606  is engaged against the tubular thereby preventing flow past an annulus between the anchoring assembly  600  and the tubular. 
     The actuation assembly  612  may include two or more valves  632 , a first piston  634 , a second piston  636 , and a fluid located in a first piston chamber  638  and a second piston chamber  640 . The first piston  634  and the second piston  636  are fixed to the inner mandrel  604 . Further, the first piston  634  and the second piston  636  have a fluid seal, for example an o-ring, which seals the annulus between the inner mandrel  604  and the outer mandrel  614 . 
     The first piston chamber  638 , as shown in  FIG. 6 , is defined by the space between the inner mandrel  604 , the outer mandrel  614 , the first piston and the two or more valves  632 . The second piston chamber  640 , as shown in  FIG. 6 , is defined by the space between the inner mandrel  604 , the outer mandrel  614 , the second piston  636  and the two or more valves  632 . The two or more valves  632  control the flow of the fluid between the first piston chamber  638  and the second piston chamber  640  as the inner mandrel  604  is manipulated relative to the J-pin as will be described in more detail below. 
       FIG. 8  shows a cross sectional view of the two or more valves  632 . The two or more valves  632  include one or more one way valves  800  and at least one relief valve  802 , located in an annular body  804 . The annular body  804  may be located between the inner mandrel  604  and the outer mandrel  614 . In one embodiment, the annular body  804  is fixed to the outer mandrel  614 , while the inner mandrel  604  is allowed to move relative to the annular body  804 . It should be appreciated that in another embodiment the annular body  804  may be fixed to the inner mandrel  604 , while the outer mandrel  614  is allowed to move relative to the annular body  804 . Further, it should be appreciated that the general location and arrangement of the piston chambers, the valves, actuation assembly and the anchor may be moved so long as the actuation assembly can set and release the anchor. 
     The one or more one way valves  800  allow fluid from the first piston chamber  638  to flow into the second piston chamber  640  as the inner mandrel  604  moves down relative to the outer mandrel  614 . Once the fluid flows into the second piston chamber, the one or more one way valves prevent fluid flow back into the first piston chamber  638 . Thus, as the inner mandrel moves down from the preset position PSP to the set position SP, the one or more one way valves  800  allow the inner mandrel  604  to move down while preventing the inner mandrel  604  from moving up relative to the outer mandrel  614 . This ensures that the sealing element  606  and the anchor  608  are set and not released as the inner mandrel is moved down. 
       FIG. 6  shows the inner mandrel  604  and the J-pin  620  in the run in position RIP. In order to move the inner mandrel  604  and thereby the J-pin  620  to the preset position PSP, the inner mandrel  604 , the first piston  634 , and the second piston  636  must move up relative to the J-pin  620  and the outer mandrel  614 . The upward movement of the inner mandrel  604  causes the second piston chamber  640  to lose volume and the first piston chamber  638  to gain volume. However, one or more one way valves  800  and at least one relief valve  802  will not allow fluid to flow through the one or more valves  632  without increasing the pressure to the predetermined pressure to activate the relief valve  802 . Therefore, a fluid path  900 , shown in  FIG. 9A , provides a bypass of the two or more valves  632 . The fluid path  900  is open when the J-pin  620  is in the run in position RIP. Therefore, as the J-pin  620  moves down relative to the inner mandrel  604  from the run in position RIP to the preset position PSP, fluid freely bypasses the two or more valves  612 . This allows the volume in the first piston chamber  638  to increase as the J-pin  620  moves to the preset position. The movement of the inner mandrel  604  and the J-pin  620  to the preset position closes the fluid path  900 . Thus, when the inner mandrel  604  begins to move from the preset position PSP to the set position SP, the fluid may only move between the first piston chamber  638  and the second piston chamber  640  through the two or more valves  632 . 
     In one embodiment, the fluid path  900  is opened and closed by a moveable seal  902  moving from an unsealed to a sealed position. The moveable seal  902  is not seated in a groove  904  when the J-pin is in the run in position RIP. When the inner mandrel  604  begins to move down toward the preset position PSP, the inner mandrel  604  pushes the moveable seal  902  into the groove  904  thereby sealing the two or more valves  632  between the inner mandrel  604  and the outer mandrel  614 . The moveable seal  902  remains in this position until the anchor is ready to be removed from the tubular. The movement of the J-pin  620  between the pull out of hole position POOH and the run in position RIP moves the moveable seal  902  from the sealed position to the unsealed position thereby opening the fluid path  900 . 
     In an alternative embodiment, the seal is not moved and a fluid resistor (not shown) is used in addition to or as an alternative to the relief valve  802 . The fluid resistor allows fluid to flow slowly past the two or more valves  632  if a continuous force and fluid pressure is applied to it. The fluid resistor will not allow fluid past it in the event of quick impact loads. Therefore, as the inner mandrel  604  moves from the run in position RIP to the preset position PSP, the fluid resistor slowly allows the fluid to move from the second piston chamber  640  to the first piston chamber  638 . Once the J-pin is in the preset position PSP, the one way valves  800  allow the inner mandrel  604  to operate in the manner described above. 
     To release the anchor  608 , the inner mandrel must be moved from the set position SP to the pull out of hole position POOH. A tensile or upward force is applied to the conveyance thereby causing the inner mandrel  604  to attempt to move up relative to the J-pin  620 , the two or more valves  632 , and the outer mandrel  614 . This upward force puts the fluid in the second piston chamber  640  into compression. The one way valves  800  prevent the fluid from flowing past the two or more valves  632 . The increased pulling on the inner mandrel  604  increases the pressure in the second piston chamber  640  until the predetermined pressure of the relief valve  802  is reached. The predetermined pressure causes the relief valve  802  to go off thereby allowing the fluid in the second chamber  640  to freely flow into the first chamber  638 . This allows the inner mandrel  604  to move up thereby releasing the anchor  608  and the sealing element  606 . When the J-pin  620  has reached the pull out of hole position POOH, the anchor  608  is no longer engaged with the tubular. The relief valve  802  may automatically reset once the fluid pressure in the second piston chamber  640  is relieved. 
     Thus, in the alternative embodiment the anchor assembly  600  is run into the hole with the J-pin  620  in the run in position RIP. The engagement member  610  engages the inner wall of the tubular. The anchor assembly  600  travels in the tubular until a desired location is reached. The inner mandrel  604  is then lift up and the engagement member  610  maintains the J-pin  620 , the outer mandrel  614 , the two or more valves  632 , and the stationary slip block  646  in a stationary position. The upward movement of the inner mandrel  604  causes the second fluid chamber  640  to lose volume thereby pushing fluid past the fluid path  900  into the first fluid chamber. The continued movement of the inner mandrel  604  moves the J-pin  620  from the run in position RIP to the preset position PSP. As the inner mandrel  604  moves from the run in position RIP to the preset position PSP the moveable seal  902  is set thereby sealing the two or more valves  632  between the outer mandrel  614  and the inner mandrel  604 . The sealing element  606  and the anchor  608  may then be set by removing the upward force from the inner mandrel  604  and allowing the inner mandrel to move down thereby moving the J-pin  620  to the set position SP. The downward movement of the inner mandrel  604  causes the cap  602  to engage the gage ring  618 . The gage ring  618  applies force to the sealing element  606  and the floating slip blocks  642 . The floating slip block  642  wedges the slips  644  against the stationary slip blocks  646  thereby moving the slips  644  radially outward and into engagement with the inner wall of the tubular. The compression of the sealing element  606  causes the sealing element to sealing engage the inner wall of the tubular. As the inner mandrel  604  moves from the preset position PSP to the set position SP, the fluid path  900  is closed. With the anchor assembly  600  set in the tubular, a downhole operation may be performed. In one example a progressive cavity pump, as described above, is used to pump production fluid from the tubular. 
     The downhole operation is performed until it is desired to move or remove the anchor assembly  600  from the tubular. To disengage the anchor assembly  600 , the inner mandrel  604  is pulled up. This causes the pressure in the second piston chamber  640  to increase due to the one way valves  800  not allowing flow past the two or more valves  632 . The pressure is increased in the second piston chamber  640  until the relief valve  802  is set off. The fluid is then free to flow to the first piston chamber  638  thereby allowing the inner mandrel  604  to move up relative to the slips  644  and the outer mandrel  614 . The upward movement of the inner mandrel  604  causes the slips  644  and the sealing element  606  to disengage the tubular. The inner mandrel  604  now has the J-pin in the pull out of hole position. If desired, continued pulling on the conveyance will remove the anchor assembly  600  from the wellbore. If it is desired to relocate and/or reset the tool downhole, the inner mandrel  604  is allowed to move down relative to the engagement member  610 . This allows the inner mandrel  604  and the J-pin  620  to move back to the run in position RIP. As the inner mandrel  604  moves toward the run in position RIP, the fluid path  900  is reopened. The anchor assembly is now free to move to a second location in the tubular and perform another downhole operation. 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.