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BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments of the present invention generally relate to an artificial lift system for well production. 
     2. Description of the Related Art 
     One type of adverse well production is steam assisted gravity drainage (SAGD). SAGD wells are quite challenging to produce. They are known to produce at temperatures above two hundred degrees Celsius. They are typically horizontally inclined in the producing zone. The produced fluids can contain highly viscous bitumen, abrasive sand particles, high temperature water, sour or corrosive gases and steam vapor. Providing oil companies with a high volume, highly reliable form of artificial lift is greatly sought after, as these wells are quite costly to produce due to the steam injection needed to reduce the in-situ bitumen&#39;s viscosity to a pumpable level. 
     For the last decade, the artificial lift systems deployed in SAGD wells have typically been Electrical Submersible Pumping (ESP) systems. Although run lives of ESP systems in these applications are improving they are still well below “normal” run times, and the costs of SAGD ESPs are three to four times that of conventional ESP costs. 
     SUMMARY OF THE INVENTION 
     Embodiments of the present invention generally relate to an artificial lift system for well production. In one embodiment, a method of pumping production fluid from a wellbore includes deploying a centrifugal pump into a production wellbore; and pumping hydrocarbons from the production wellbore by rotating an impeller of the centrifugal pump in the production wellbore from surface using a drive string, wherein the impeller is rotated at a speed less than or equal to seventeen hundred fifty revolutions per minute. 
     In another embodiment, a downhole assembly of an artificial lift system includes: a receptacle for receiving a coupling of a drive string, the receptacle including a housing having a coupling for connection to a production tubing string and a shaft; a centrifugal pump including a housing connected to the receptacle housing and a shaft connected to the receptacle shaft; a thrust chamber including: a housing connected to the pump housing, a shaft torsionally and longitudinally connected to the pump shaft, a thrust bearing having a thrust driver longitudinally and torsionally connected to the pump shaft and a thrust carrier longitudinally and torsionally connected to the chamber housing, wherein: the thrust bearing is operable to receive thrust from the pump shaft, and the thrust bearing is in fluid communication with a pumped fluid path. 
    
    
     
       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. 1  illustrates an artificial lift system (ALS) pumping production fluid from a steam assisted gravity drainage (SAGD) well, according to one embodiment of the present invention. 
         FIGS. 2A-C  illustrate a downhole assembly of the ALS. 
         FIG. 3A  illustrates a rod receptacle of the downhole assembly.  FIG. 3B  illustrates a pump of the downhole assembly. 
         FIG. 4A  illustrates a thrust chamber of the downhole assembly.  FIG. 4B  illustrates an intake of the downhole assembly. 
         FIGS. 5A-5D  illustrate a stabilizer of the ALS. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  illustrates an artificial lift system (ALS)  50   h, r, d  pumping production fluid, such as bitumen  8   p  (aka tar sand or oil sand), from a steam assisted gravity drainage (SAGD) well  1 , according to one embodiment of the present invention. Alternatively, the production fluid may be heavy crude oil or oil shale. The ALS  50   h, r, d  may include a drive head  50   h , a drive string  50   r , and a downhole assembly  50   d . The SAGD well  1  may include an injection well  1   i  and a production well  1   p . Each well  1   i, p  may include a wellhead  2   i, p  located adjacent to a surface  4  of the earth and a wellbore  3   i, p  extending from the respective wellhead. Each wellbore  3   i, p  may extend from the surface  4  vertically through a non-productive formation  6   d  and horizontally through a hydrocarbon-bearing formation  6   h  (aka reservoir). Alternatively the horizontal portions of either or both wellbores may be other deviations besides horizontal. Alternatively, the injection well may be omitted and the ALS may be used to pump production fluid from other types of adverse production wells, such as high temperature wells. 
     Surface casings  9   i, p  may extend from respective wellheads  2   i, p  into respective wellbores  3   i, p  and each casing may be sealed therein with cement  11 . The production well  1   p  may further include an intermediate casing  10  extending from the production wellhead  2   p  and into the production wellbore  3   p  and sealed therein with cement  11 . The injection well  1   i  may further include an injection string  15  having an injection tubing string  15   t  extending from the injection wellhead  2   i  and into the injection wellbore  3   i  and having a packer  15   p  for sealing an annulus thereof. 
     A steam generator  7  may be connected to the injection wellhead  2   i  and may inject steam  8   s  into the injection wellbore  3   i  via the injection tubing string  15   t . The injection wellbore  3   i  may deliver the steam  8   s  into the reservoir  6   h  to heat the bitumen  8   p  into a flowing condition as the added heat added reduces viscosity thereof. The horizontal portion of the production wellbore  3   p  may be located below the horizontal portion of the injection wellbore  3   i  to receive the bitumen drainage  8   p  from the reservoir  6   h.    
     A production string  12  may extend from the production wellhead  2   p  and into the production wellbore  3   p . The production string  12  may include a string of production tubing  12   t  and the downhole assembly  50   d  connected to a bottom of the production tubing. A slotted liner  13  may be hung from a bottom of the intermediate casing  10  and extend into an open hole portion of the production wellbore  3   p . The downhole assembly  50   d  may be located adjacent a bottom of the intermediate casing  10 . Alternatively, the downhole assembly  50   d  may be located within the slotted liner  13 . An instrument string  14  may extend from the production wellhead  2   p  and into the production wellbore  3   p . The instrument string  14  may include a cable  14   c  and one or more sensors  14   i, o  in data communication with the cable. The sensors  14   i, o  may include a first  14   i  pressure and/or temperature sensor in fluid communication with the bitumen  8   p  entering the downhole assembly  50   d  and a second  14   o  pressure and/or temperature sensor in fluid communication with the bitumen discharged from the downhole assembly. 
     The drive head  50   h  may include a motor  51 , a transmission  52 , an output shaft  53 , a clamp  54 , a stuffing box  55 , a frame  56 , a thrust bearing  57 , and a drive shaft, such as a polished rod  58 . The motor  51  may be electric, such as a two-pole, three-phase, squirrel-cage induction type and may operate at a nominal rotational speed  59   m  of thirty-five hundred revolutions per minute (RPM) at sixty Hertz (Hz). Alternatively, the motor may be hydraulic or pneumatic. A housing of the motor  51  may be connected to the frame  56 . The frame  56  may be connected to the wellhead  2   p . A shaft of the motor  51  may be connected to the transmission  52 . The transmission  52  may be a belt and sheave, roller chain and sprockets, or a gearbox. Alternatively, the drive head may be direct drive (no transmission). The output shaft  53  may be connected to the transmission  52 . The transmission  52  may rotate the output shaft  53  at a rotational speed  59   o  less than the motor rotational speed  59   m . The speed ratio (output speed  590   o  divided by motor speed  59   m ) of the transmission  52  may be less than or equal to one-half, nine-twentieths, three-eighths, or one-third such that the output speed  59   o  may be less than or equal to (about) seventeen hundred fifty, sixteen hundred, thirteen hundred, or twelve hundred RPM, respectively. 
     The polished rod  58  may be connected to the output shaft  53  by the clamp  54 . The clamp  54  may torsionally and longitudinally connect the output shaft  53  and the polished rod  58  such that the polished rod is driven at the output speed  59   o  and the output shaft may transfer weight of the drive string  50   r  to the thrust bearing  57 . The polished rod  58  may be longitudinally and torsionally connected to the drive string  50   r , such as by a threaded connection (not shown), such that the drive string is also driven at the output speed  59   o . The drive string  50   r  may extend from the production wellhead  2   p  and into the production wellbore  3   p . The drive string  50   r  may include a continuous sucker rod  60 , stabilizers  61  spaced therealong at regular intervals, and a rod coupling  62  ( FIGS. 2A and 3A ). Alternatively, the drive string may include a jointed sucker rod string (sucker rods and couplings), coiled tubing, or a drill pipe string instead of the continuous sucker rod. 
       FIGS. 2A-C  illustrate the downhole assembly  50   d . The downhole assembly  50   d  may include a rod receptacle  100 , a pump  200 , a thrust chamber  300 , and an intake  400 . 
       FIG. 3A  illustrates the rod receptacle  100 . The rod receptacle  100  may include a housing  101  and a shaft  105  disposed in the housing and rotatable relative thereto. 
     The rod coupling  62  may be longitudinally and torsionally connected to a bottom of the continuous sucker rod  60 , such as by a threaded connection. The rod coupling  62  may include a tubular body  62   b . Ribs  62   r  may be formed along an outer surface of the body  62   b  and spaced therearound. Flow passages may be formed between the ribs  62   r  to minimize flow obstruction by the ribs. The ribs  62   r  may facilitate alignment of the rod coupling  62  with the receptacle shaft  105  when landing the rod coupling into the rod receptacle  100 . An upper portion of the coupling body  62   b  may have a threaded inner surface  62   t  for connection to the continuous sucker rod  60 . Splines  62   s  may be formed along and spaced around an inner surface of a mid and lower portion of the body  62   b . A shoulder may be formed at an upper end of the body  62   b  for receiving the continuous sucker rod  60 . 
     A conical landing guide  62   c  may be formed at a lower end of the body  62   b  to also facilitate alignment of the rod coupling  62  with the receptacle shaft  105  when landing the rod coupling into the rod receptacle  100 . A clearance formed between the ribs  62   r  and an inner surface of the receptacle housing  101  may be less than or equal to a clearance formed between the receptacle shaft  105  and a maximum diameter of the landing guide  62   c  to ensure that the receptacle shaft is received by the landing guide  62   c . Engagement of the landing guide  62   c  with the receptacle shaft  105  may even lift the rod coupling  62  from a bottom of the production tubing  12   t . The rod coupling  62  may further have one or more relief ports (not shown) formed through a wall thereof for exhausting debris during landing of the rod coupling into the receptacle  100 . 
     The receptacle housing  101  may include an upper connector portion  102 , a tubular mid portion  103 , and a lower connector portion  104 . The upper connector portion  102  may flare outwardly from the mid portion  103  and have a threaded inner surface  102   t  for connection to the bottom of the production tubing  12   t . An outer surface of the production tubing bottom may also be threaded (not shown). The upper connector portion  102  may also have a fishing profile  102   p  formed in an outer surface thereof to facilitate retrieval of the downhole assembly  50   d  in case the downhole assembly becomes stuck in the production wellbore  3   p  and cannot be removed using the production tubing  12   t . The lower connector portion  104  may have a flange  104   f  formed in an outer surface thereof and a nose  104   n  formed at a lower end thereof. The flange  104   f  may have holes formed therethrough for receiving threaded fasteners, such as bolts  104   b . The nose  104   n  may have a groove formed in an outer surface thereof for carrying a seal, such as an o-ring  104   s . A stopper  110  may be disposed in the mid portion  103  and longitudinally connected thereto, such as by a threaded connection. The stopper  110  may have a bore accommodating the shaft  105  and a flow passage formed therethrough for accommodating pumping of the bitumen  8   p . 
     The receptacle shaft  105  may include a solid core portion  105   c , splines  105   s  formed along and spaced around an outer surface of the core portion, a guide nose  105   n  formed at an upper end thereof, and a landing guide formed at a lower end thereof. The guide nose  105   n  may be convex and have a spiral profile formed therein. The landing guide may be a serration  105   j  formed in a lower end of each of the splines  105   s . When landing the rod coupling  62  into the rod receptacle  100 , the guide nose  105   n  may engage the rod coupling splines  62   s  and rotate the receptacle shaft  105  relative to the rod coupling to align the receptacle splines  105   s  with spline-ways of the rod coupling (and vice versa). Mating of the splines  62   s ,  105   s  may torsionally connect the rod coupling  62  and the receptacle shaft  105  while allowing relative longitudinal movement therebetween. After mating of the receptacle and rod coupling splines  62   s ,  105   s , lowering of the rod coupling  62  may continue until the lower end of the rod coupling body seats on the stopper  110 . The lowering may be accommodated by the extended splines  62   s  of the rod coupling  62 . Once seated, the rod coupling  62  may be raised into the operational position shown and the continuous sucker rod  60  clamped  54 , thereby ensuring that the downhole assembly  50   d  does not bear the weight of the continuous sucker rod. The receptacle shaft  105  may further include shaft retainers (not shown) for longitudinally restraining the shaft within the receptacle housing  101  during assembly and deployment of the downhole assembly  50   d . The shaft retainers may engage the stopper  110  while allowing limited relative longitudinal movement of the shaft  105  relative to the housing  101  to accommodate operation of the receptacle shaft. 
       FIG. 3B  illustrates the pump  200 . The pump  200  may include a housing  201  and a shaft  205  disposed in the housing and rotatable relative thereto. To facilitate assembly, the pump housing  201  may include one or more sections  202 - 204 , each section longitudinally and torsionally connected, such as by a threaded connection and sealed, such as by as an o-ring. Each housing section  202 - 204  may further be torsionally locked, such as by a tack weld (not shown). An upper connector section  202  may have a flange  202   f  formed at an upper end thereof and a seal face formed in an inner surface thereof. The flange  202   f  may have threaded sockets  202   s  formed therein for receiving shafts of the receptacle bolts  104   b , thereby fastening the flanges  104   f ,  202   f  together and forming a longitudinal and torsional flanged connection between the receptacle housing  101  and the pump housing  201 . The seal face may receive the receptacle nose  104   n  and seal  104   s , thereby sealing the flanged connection. A lower connector portion  204  may have a flange  204   f , a nose  204   n , o-ring  204   s , and bolts  204   b  similar to those discussed above for the receptacle  100 . 
     The pump  200  may further include a shaft coupling  262  for longitudinally and torsionally connecting the receptacle shaft  105  and the pump shaft  205 . The shaft coupling  262  may include a tubular body  262   b . Splines  262   s  may be formed along and spaced around an inner surface of body  262   b . A guide profile, such as a serration  262   j , may be formed in an upper end of each of the splines  262   s  and may correspond to the receptacle shaft serration  105   j . A support, such as a pin  262   p , may extend across a bore of the body  262   b . The pin  262   p  may be longitudinally connected to the body  262   b , such as by fasteners  262   f . The body  262   b  may have threaded holes formed through a wall thereof for receiving the fasteners  262   f  and the pin  262   p  may have a groove formed therein for receiving tips of the fasteners, thereby longitudinally connecting the pin and the body. 
     When assembling the downhole assembly  50   d  for deployment into the production wellbore  3   p , the receptacle  100  may be lowered onto the pump  200 . As the receptacle  100  is lowered onto the pump  200 , the receptacle serrations  105   j  may engage the shaft coupling serrations  262   j . Engagement of the serrations  105   j ,  262   j  may rotate the receptacle shaft  105  relative to the shaft coupling  262  to align the receptacle splines  105   s  with spline-ways of the shaft coupling (and vice versa). Mating of the splines may torsionally connect the shaft coupling  262  and the receptacle shaft  105  while allowing relative longitudinal movement therebetween. After mating of the receptacle and shaft coupling splines  105   s ,  262   s , lowering of the receptacle  100  may continue until a lower end of the receptacle shaft  105  seats on the shaft coupling pin  262   p , thereby longitudinally supporting the receptacle shaft  105  from the shaft coupling  262 . After seating of the receptacle shaft  105 , lowering of the receptacle  100  may continue until the receptacle flange  104   f  is adjacent the upper pump flange  202   f . The flanges  104   f ,  202   f  may be manually aligned, seated, and fastened. 
     The pump shaft  205  may include a solid core portion  205   c , upper  205   u  and lower  205   b  splines formed at and spaced around respective ends of the core portion, a keyway  205   w  ( FIGS. 2A and 2B ) formed along the core portion, and a landing guide formed at a lower end thereof. The landing guide may be a serration  205   j  formed in a lower end of each of the splines  205   s . The shaft coupling  262  may be manually installed on the pump shaft upper end, thereby engaging the upper splines  205   u  with the coupling splines  262   s  and seating the coupling pin  262   p  on the shaft upper end. The installation may longitudinally and torsionally connect the pump shaft  205  to the shaft coupling  262 . 
     The pump shaft  205  may be supported for rotation relative to the housing by radial bearings  206   u, b . Each radial bearing  206   u, b  may include a body, an inner sleeve, and an outer sleeve. The sleeves may be made from a wear-resistant material, such as a tool steel, ceramic, or ceramic-metal composite (aka cermet). Each inner sleeve may be longitudinally connected to the pump shaft  205 , such as by retainers (i.e., snap rings) engaged with respective grooves formed in an outer surface of the shaft core  205   c , and torsionally connected to the shaft, such as by a press fit or key. Each outer sleeve may be longitudinally and torsionally connected to the bearing body, such as by a press fit. Each bearing body may be longitudinally and torsionally coupled to the respective housing sections  202 ,  204 , such as by a press fit. Each bearing body may have flow passages formed therethrough for accommodating pumping of the bitumen  8   p  and the bearings may utilize the pumped bitumen for lubrication. 
     The pump  200  may be centrifugal, such as a radial flow or mixed axial/radial flow centrifugal pump. The pump  200  may include one or more stages  210   a, b  (six stages shown in  FIGS. 2A and 2B ). Each stage  210   a, b  may include an impeller  211  a diffuser  212 , and an impeller spacer. Each even stage  210   b  may include a radial bearing  213  having an inner sleeve torsionally connected to the pump shaft, such as by a key (not shown) and keyway  205   w , and an outer sleeve longitudinally and torsionally connected to the respective diffuser, such as by a press fit. The bearing sleeves  213  may be made from the wear resistant material, discussed above for the radial bearings  206   u, b . Alternatively, each odd stage may include the bearing instead of the even stage or each stage may include the bearing. Each impeller  211  and impeller spacer may be torsionally connected to the pump shaft  205 , such as by a key (not shown) and keyway  205   w . The impellers  211  and impeller spacers may be longitudinally connected to the pump shaft  205  by compression between a compression fitting  207  and a retainer, such as a snap ring  208 . 
     The compression fitting  207  may include a sleeve  207   s , a nut  207   n , a retainer, such as a snap ring  207   r , and fasteners, such as set screws  207   f . The snap ring  207   r  may be received in a groove formed in an outer surface of the shaft core  205   c  after the rest of the fitting has been disposed on the shaft core. The snap ring  208  may be installed on the shaft core  205   c  before the impellers  211  and may have a shoulder for receiving an impeller spacer. The snap ring  207   r  may have a shoulder for receiving the nut  207   n . The sleeve  207   s  may be torsionally connected to the shaft  205 , such as by a key (not shown) and keyway  205   w . The sleeve  207   s  may have a threaded outer surface for receiving a threaded inner surface of the nut  207   n . Rotation of the nut  207   n  relative to the sleeve  207   s  may longitudinally drive the sleeve into engagement with an impeller spacer, thereby compressing the impellers, impeller bearings, and impeller spacers. Once tightened to a predetermined torque, the nut  207   n  may be torsionally connected to the compression sleeve  207   s  by installing or tightening the set screws  207   f . Rotation of the nut  207   n  relative to the sleeve  207   s  may longitudinally drive the sleeve into engagement with an impeller spacer, thereby compressing the impellers, impeller bearings, and impeller spacers. Once tightened to a predetermined torque, the nut  207   n  may be torsionally connected to the compression sleeve  207   s  by installing or tightening the set screws  207   f.    
     The diffusers  212  may be longitudinally and torsionally connected to the pump housing  201 , such as by compression between the upper  202  and lower  204  connector sections (and diffuser spacers). Rotation of each impeller  211  by the pump shaft  205  may impart velocity to the bitumen  8   p  and flow through the stationary diffuser  212  may convert a portion of the velocity into pressure. The pump  200  may deliver the pressurized bitumen  8   p  to the production tubing  12   t  via the receptacle  100 . 
       FIG. 4A  illustrates the thrust chamber  300 . The thrust chamber  300  may include a housing  301  and a shaft  305  disposed in the housing and rotatable relative thereto. To facilitate assembly, the chamber housing  301  may include one or more sections  302 - 304 , each section longitudinally and torsionally connected, such as by a threaded connection and sealed, such as by as an o-ring. Each housing section  302 - 304  may further be torsionally locked, such as by a tack weld (not shown). An upper connector section  302  may have a flange  302   f  formed at an upper end thereof and a seal face formed in an inner surface thereof. The flange  302   f  may have threaded sockets  302   s  formed therein for receiving shafts of the lower pump flange bolts  204   b , thereby fastening the flanges  204   f ,  302   f  together and forming a longitudinal and torsional flanged connection between the pump housing  201  and the chamber housing  301 . The seal face may receive the lower pump flange nose  204   n  and seal  204   s , thereby sealing the flanged connection. A lower connector portion  304  may have a flange  304   f , a nose  304   n , o-ring  304   s , and bolts  304   b  similar to those discussed above for the receptacle  100 . 
     The thrust chamber  300  may further include a shaft coupling  362  for longitudinally and torsionally connecting the pump shaft  205  and the chamber shaft  305 . The chamber shaft coupling  362  may be similar to the pump shaft coupling  262 , discussed above and assembly of the pump  200  onto the thrust chamber  300  may be similar to assembly of the receptacle  100  onto the pump  200 , discussed above. The chamber shaft  305  may include a solid core portion  305   c , upper  305   u  and lower splines formed at and spaced around respective ends of the core portion, a keyway  305   w  ( FIGS. 2B and 2C ) formed along the core portion, and a landing guide formed at a lower end thereof. Alternatively, the lower splines and/or the lower landing guide may be omitted. The chamber shaft  305  may be supported for rotation relative to the chamber housing by radial bearings  306   u, b , similar to the pump radial bearings  206   u, b , discussed above. 
     The thrust chamber  300  may further include one or more thrust bearings  310   a - d . Each thrust bearing  310   a - d  may include a thrust driver  311 , a thrust carrier  312 , a radial bearing  314   s , a runner thrust disk  314   d , and a carrier pad  313 . The thrust bearings  310   a - d  may receive both impeller thrust and pressure thrust from the rotating pump shaft  205  via the shaft coupling  362  and be capable of transferring the thrusts to the stationary production tubing  12   t  via housings  101 - 301 . 
     Each thrust driver  311 , radial bearing  314   s , and runner spacer may be torsionally connected to the chamber shaft  305 , such as by a key (not shown) and keyway  305   w . The thrust drivers  311 , radial bearings  314   s , and runner spacers may be longitudinally connected to the chamber shaft  305  by compression between a compression fitting  307  and a retainer, such as a snap ring  308 . The compression fitting  307  may be similar to the pump compression fitting  207 , discussed above. Each thrust disk  314   d  may be received in a recess formed in the respective thrust driver  311 . Each thrust disk  314   d  may be longitudinally connected to the thrust driver  311 , such as by a press fit. Each thrust disk  314   d  may be torsionally connected to the thrust driver  311 , such as by a fastener (i.e., a pin  315   t ). Each pin  315   t  may be received by a hole formed through the respective thrust driver  311  at a periphery thereof and extend into an opening formed through the respective thrust disk  314   d  at a periphery thereof. The pin  315   t  may be press fit into the thrust driver hole. The thrust disks  314   d , carrier pads  313 , and radial bearings  314   s  may each be made from the wear resistant material, discussed above for the radial bearings  206   u, b.    
     Each thrust disk  314   d  may have lubricating grooves  316   t  formed in a bearing face thereof. The lubricating grooves  316   t  may be radial, tangential, angled, or spiral and may extend partially or entirely across the bearing face. Each thrust driver  311  may have a lubrication passage  311   p  formed therethrough in fluid communication with the recess. Each thrust driver  311  may further have a debris passage  311   e  formed therethrough for exhausting debris from a thrust interface between the thrust disk  314   d  and a thrust portion of the carrier pad  313 . Each radial bearing  314   s  may be a sleeve and operable to radially support rotation of the thrust drivers  311  relative to the thrust carriers  312  by engagement with a radial portion of the respective carrier pad  313 . 
     The carriers  312  may be longitudinally and torsionally connected to the chamber housing  301 , such as by compression between the upper  302  and lower  304  connector sections (and spacers). Each carrier pad  313  may be received in a recess formed in the respective carrier  312 . Each carrier pad  313  may be longitudinally connected to the carrier  312 , such as by a press fit. Each carrier pad  313  may be torsionally connected to the carrier, such as by a fastener (i.e., a pin  315   c ). Each pin  315   c  may be received by a hole formed through the respective carrier  312  at a periphery thereof and extend into an opening formed through the respective carrier at a periphery thereof. The pin  315   c  may be press fit into the carrier hole. Each carrier pad  313  may have a thrust portion and a radial portion, each portion perpendicular to the other, thereby forming a T-shaped cross section. Alternatively, a separate carrier disk and a carrier sleeve may be used instead of the T-shaped carrier pad. A thrust portion of each carrier pad  313  may have lubricating grooves  316   c  formed in a bearing face thereof, similar to the runner disk grooves  316   t , discussed above. Each carrier may have a lubrication passage  312   p  formed therethrough in fluid communication with the recess. Each carrier  312  may also have a flow passage  312   f  formed therethrough for accommodating pumping of the bitumen  8   p  and the thrust bearings  310   a - d  may utilize the pumped bitumen for lubrication via passages  311   p ,  312   p.    
       FIG. 4B  illustrates the intake  400 . The intake  400  may include a housing  401  and a flow tube  405  disposed in the housing and rotatable relative thereto. To facilitate assembly, the intake housing  401  may include one or more sections  402 - 404 , each section longitudinally and torsionally connected, such as by a threaded connection and sealed, such as by as an o-ring. Each housing section  402 - 404  may further be torsionally locked, such as by a tack weld (not shown). An upper connector section  402  may have a flange  402   f  formed at an upper end thereof and a seal face formed in an inner surface thereof. The flange  402   f  may have threaded sockets  402   s  formed therein for receiving shafts of the lower chamber flange bolts  304   b , thereby fastening the flanges  304   f ,  402   f  together and forming a longitudinal and torsional flanged connection between the chamber housing  301  and the intake housing  401 . The seal face may receive the lower chamber flange nose  304   n  and seal  304   s , thereby sealing the flanged connection. A lower connector portion  404  may have a flange  404   f , a nose  404   n , o-ring  404   s , and bolts  404   b  similar to those discussed above for the receptacle  100 . 
     A mid housing section  403  may have one or ports  403   p  formed through a wall thereof for receiving the bitumen  8   p  from the production wellbore  3   p . The ports  403   p  may be formed along and spaced around the mid housing section  403 . The flow tube  405  may one or more ports  405   p  formed through a wall thereof. The flow tube may also have one or more weights  405   g  formed in an outer surface thereof or disposed thereon, such as by a weld. The weights  405   g  may be located adjacent each port  405   p . Each weight  405   j  may include a pair of bands and fasteners (not shown) for assembly of the weight adjacent each port  405   p . Each tube port  405   p  may also extend to a location adjacent the housing ports  403   p . The flow tube  405  may be supported for rotation relative to the housing  401  by one or more radial bearings  406   u, b . Each radial bearing  406   u, b  may be rolling element bearing, such as a needle bearing. When the downhole assembly  50   d  is deployed in the horizontal portion of the production wellbore  3   p , the weights  405   g  may create eccentricity in the flow tube  405 , thereby causing the flow tube to rotate relative to the housing  401  such that the flow tube ports  405   p  face downwardly in the production wellbore  3   p . This may utilize a natural separation effect in the production wellbore  3   p  such that the flow tube ports  405   p  intake the bitumen  8   p  rather than steam vapor or other gas. 
     The downhole assembly  50   d  may further include a guide shoe  450 . The guide shoe  450  may have a flange formed at an upper end thereof and a seal face formed in an inner surface thereof. The flange may have threaded sockets formed therein for receiving shafts of the lower intake flange bolts  404   b , thereby fastening the flanges together and forming a longitudinal and torsional flanged connection between the intake housing  401  and the guide shoe  450 . The seal face may receive the lower intake flange nose  404   n  and seal  404   s , thereby sealing the flanged connection. 
       FIGS. 5A-5D  illustrate the stabilizer  61 . The stabilizer  61  may include a collar  501 , a sleeve  502 , and a clamp  503 . The collar  501  may be rotatable relative to the sleeve  502 . The sleeve  502  may be operable to engage an inner surface of the production tubing  12   t  and radially support rotation of the collar  501  therefrom. The collar  501  may include a pair of bands  501   a, b . Each band  501   a, b  may be semi-tubular and include a hole  501   h  formed tangentially through a wall thereof and a threaded socket  501   s  tangentially formed in the wall. Each hole  501   h  and mating socket  501   s  may receive a threaded fastener  504 , thereby longitudinally and torsionally connecting the collar bands  501   a, b  together. Connection of the collar bands  501   a, b  around the continuous sucker rod  60  may longitudinally and torsionally connect the collar  501  to the rod  60  by compressing an inner surface of the bands  501   a, b  against the rod  60 . 
     The sleeve  502  may include a pair of bands  502   a, b . Each band  502   a, b  may be semi-tubular and have connector profiles, such as dovetails  502   d , formed therealong. Engagement of the dovetails  502   d  may torsionally connect the sleeve bands  502   a, b  together. The sleeve bands  502   a, b  may be longitudinally connected by entrapment between a shoulder formed at an upper end of the collar  501  and the clamp  503 . The entrapment may also longitudinally connect the sleeve  502  and the collar  501 . The sleeve  502  may further have ribs  502   r  formed along and spaced around an outer surface thereof. The ribs  502   r  may engage an inner surface of the production tubing  12   t  while minimizing obstruction to pumping of the bitumen  8   p  through the production tubing. 
     The clamp  503  may include a pair of bands, such as a major band  503   a  and a minor band  503   b . Each band  503   a, b  may be arcuate and the major band  503   a  may include a pair of holes  503   h  formed through a wall thereof. Correspondingly, the minor band may include pair of threaded sockets  503   s  formed in a wall thereof. Each hole  503   h  and mating socket  503   s  may receive a threaded fastener  505 , thereby longitudinally and torsionally connecting the bands  503   a, b  together. The collar  501  may have a pair of flats formed in an outer surface thereof and located at a lower end thereof. The major band  503   a  may have a pair of bosses formed in an inner surface thereof for engaging the flats. Connection of the clamp bands  503   a, b  around the collar  501  may longitudinally and torsionally connect the clamp  503  to the collar by engagement of the bosses with the flats. 
     The collar  501  and clamp  503  may be made from a metal or alloy, such as steel, stainless steel, or a nickel based alloy. The sleeve  502  may be made from a high-temperature and wear-resistant polymer, such as a cross-linked thermoplastic, a thermoset, or a copolymer. 
     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.

Summary:
A method of pumping production fluid from a wellbore includes deploying a centrifugal pump into a production wellbore; and pumping hydrocarbons from the production wellbore by rotating an impeller of the centrifugal pump in the production wellbore from surface using a drive string, wherein the impeller is rotated at a speed less than or equal to seventeen hundred fifty revolutions per minute.