The present invention generally provides a reduced downtime maintenance apparatus and method for replacing and/or repairing a subassembly in sealing equipment for oil field use. The invention allows the removal of rotating portions of a rotary drilling head without having to remove non-rotating portions. The reduction in weight and size allows a more efficient repair and/or replacement of a principal wear component such as a packer. Specifically, the packer in a rotary drilling head can be removed independent of bearings and other portions of the rotary drilling head. Furthermore, because of the relatively small size and light weight, the packer can be removed typically without having to use a crane to lift a rotary BOP and without disassembling portions of the drilling platform. In some embodiments, the packer can be removed with the drill pipe without additional equipment. Furthermore, the packer can be removed remotely without necessitating manual disengagement typically needed below the platform. The invention also provides a fluid actuated system to maintain a pre-load system on the bearing.

CROSS-REFERENCE TO RELATED APPLICATIONS 
   This application is a continuation of U.S. patent application Ser. No. 10/367,154, filed Feb. 14, 2003 now U.S. Pat. No. 6,702,012, which is a divisional of U.S. patent application Ser. No. 09/550,508, filed Apr. 17, 2000, now U.S. Pat. No. 6,547,002, which issued Apr. 15, 2003, both of which are herein incorporated by reference in their entireties. 


   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   The present invention relates to removable subassemblies in sealing equipment. Specifically, the invention relates to removable subassemblies in oil field rotary drilling head assemblies. 
   2. Description of the Related Art 
   Drilling an oil field well for hydrocarbons requires significant expenditures of manpower and equipment. Thus, constant advances are being sought to reduce any downtime of equipment and expedite any repairs that become necessary. Rotating equipment is particularly prone to maintenance as the drilling environment produces abrasive cuttings detrimental to the longevity of rotating seals, bearings, and packing glands. 
     FIG. 1  shows an exemplary drilling rig  10 . The drilling rig  10  is placed over an area to be drilled and a drilling bit (not shown) is attached to sections of drill pipe  12 . Typically, a rotary turntable  14  rotates a drive member  16 , referred to as a kelly, which in turn is attached to the drill pipe  12  and rotates the drill pipe to drill the well. In some arrangements, a kelly is not used and the drill string is rotated by a drive unit (not shown) attached to the drill pipe itself. Typically, a mixture of drilling fluids, referred to as mud, is injected into the well to lubricate the drill bit (not shown) and to wash the drill shavings and particles from the drill bit and then return up through an annulus surrounding the drill pipe  12  and out the well through an outflow line  22  to a mud pit  24 . New sections of drill pipe  12  are added to the drill pipe in the well using a crane  26  and a block and tackle  28  to collectively form a drill string  30  as the well is drilled deeper to the desired underground strata  32 . A power unit  34  powers a control unit  36  and associated motors, pumps, and other equipment (not shown) mounted on a drilling platform  38 . 
   In many instances, the strata  32  produce gas or fluid pressure which needs control throughout the drilling process to avoid creating a hazard to the drilling crew and equipment. To seal the mouth of the well, one or more blow out preventers (BOP) are mounted to the well and can form a blow out preventer stack  40 . An annular BOP  42  is used to selectively seal the lower portions of the well from a tubular body  44  which allows the discharge of mud through the outflow line  22 . A rotary drilling head  46  is mounted above the tubular body  44  and is also referred to as a rotary blow out preventer. An internal portion of the rotary drilling head  46  is designed to seal around a rotating drill pipe  30  and rotate with the drill pipe by use of a internal sealing element, referred to as a packer (not shown), and rotating bearings (also not shown) as the drill pipe is axially and slidably forced through the drilling head  46 . However, the packer wears and occasionally needs replacement. Typically, the drill string or a portion thereof is pulled from the well and a crew goes below the drilling platform  38  and manually disassembles the rotary drilling head  46 . Typically, a crane  26  is used to lift the rotary drilling head  46  which can weigh thousands of pounds. Because of the size of the drilling head  46 , portions of the drilling platform  38  and equipment are disassembled to allow access to the drilling head and to remove the drilling head from the BOP stack  40 . The drilling head  46  is replaced or reworked and crew goes below the drilling platform to reassemble the drilling head to the BOP stack  40  and operation is resumed. The process is time consuming and can be dangerous. 
   Prior efforts have sought to reduce the complexity of the drilling head replacement. For example,  FIG. 2  is a schematic cross sectional view of a rotary blow out preventer, similar to the embodiments shown in U.S. Pat. No. 5,848,643, which is incorporated herein by reference. A rotating spindle assembly  48  is disposed within a non-rotating spindle assembly  50 , which in turn, is disposed within a body  52  and held in position by lugs  54 . To remove the entire non-rotating and rotating spindle assembly from the body  52 , lugs  54  are rotated in horizontal grooves  56  and then lifted upwardly through vertical slots  58  in a “twist and lift” motion. However, the assembly can weigh about 1,500 to about 2,000 pounds and still requires use of extra lifting equipment such as the crane  26 . In addition, disassembly of the drilling platform  38  is necessary to provide access and requires manual efforts by the drilling crew. 
   Similarly, U.S. Pat. No. 3,934,887, incorporated herein by reference, discloses a BOP body having an assembly of a lower stationary housing  22  and an upper stationary housing  24 . The upper stationary housing  24  houses a stationary tapered bowl  60 , a rotating bowl  62  disposed inwardly of the tapered bowl, and bearings  66 ,  68  disposed between the stationary bowl and rotating bowl. A stripper  40  is connected to the rotating bowl  62 . A clamp  28  retains the assembly of the stationary tapered bowl  60 , the rotating bowl  62 , the bearings  66 ,  68 , and associated equipment to the upper stationary housing  24 . By unclamping the clamp  28 , the entire assembly may be removed from the BOP body. However, the removable assembly is of such size and weight with the result that crews are needed below the drilling platform and lifting equipment is necessary to lift the assembly from the BOP body. 
     FIG. 3  is a schematic cross sectional view of another rotary BOP  60 , similar to the embodiments disclosed in U.S. Pat. No. 4,825,938, incorporated herein by reference. To avoid removing the entire rotary BOP, the reference discloses a pneumatically actuated series of “dogs”  64  which engage a groove  66  on a retainer collar  68 , referred to in that disclosure as “massive”. By actuating pneumatic cylinders  70  to rotate the dogs  64  away from the groove  66 , the “massive” retainer collar  68 , the stinger  72 , stinger flange  74 , a stripper rubber  76 , and associated bearing surfaces  78 ,  80  and  82  can be removed and access gained to the inner structures to repair or replace the stripper rubber  76 . This device is similar to the preceding references in that both rotating and non-rotating portions are removed, which add weight and size to the assembly that is removed. 
   Another challenge to the rotary drilling head maintenance is bearing life. In a rotary BOP, bearings are used to reduce the friction between the fixed portions of the drilling head and the rotating drill string with rotating portions of the drilling head. As shown in  FIG. 2 , the typical assembly includes a lower bearing  84  and an upper bearing  86  axially disposed between a rotating portion  48  and a non-rotating portion  50  of the rotary BOP  50 . The bearings are tightened in position, referred to as pre-loading the bearing, by typically turning a threaded bearing retainer  88  until the bearings are pre-loaded to a desired level. As the bearings wear or otherwise change, the loading changes. The BOP must be disassembled, the bearing readjusted, and the BOP reassembled. Otherwise, the bearings can fail prematurely, causing downtime for the drilling operations. Typically, the bearing retainer is directly inaccessible after assembly into the drilling head and the drilling head must be at least partially disassembled for readjustment. 
   There remains a need for an apparatus and method for decreasing the downtime in drilling an oil well by decreasing the time required for removal and replacement/repair of the packer and decreasing the time required to adjust the bearing loading. 
   SUMMARY OF THE INVENTION 
   The present invention generally provides an apparatus and method for sealing about a member inserted through a rotatable sealing element disposed in a drilling head. The rotatable sealing element is removable separately from non-rotating and/or other rotating portions. More specifically, the invention allows a rotatable packer in a drilling head to be removable separately from non-rotating and/or other rotating portions of the drilling head. The invention also provides a fluid actuated system to maintain a pre-load system on the bearing. 
   In one aspect, the invention provides a non-rotating portion, a first rotating portion and a second rotating portion, at least one rotating portion being rotatably engaged with the non-rotating portion, and a selectively disengageable retainer disposed adjacent at least one of the rotating portions and adapted to disengage at least one of the rotating portions from the non-rotating portion. In another aspect, the invention provides a non-rotating portion, a rotating portion disposed in proximity to the non-rotating portion, at least one bearing disposed between the non-rotating portion and the rotating portion and having at least one moveable bearing race adjacent a remaining portion of the bearing, and an actuator disposed adjacent the bearing race and adapted to adjust a position of the moveable bearing race relative to the remaining portion of the bearing. In another aspect, the invention provides a method of retaining a packer in a drilling head, comprising disposing a packer in a rotating portion of the drilling head, radially moving a retainer toward the packer, the retainer being at least partially disposed in the rotating portion, and radially engaging the packer with the retainer while maintaining a portion of the retainer in the rotating portion. In another aspect, the invention provides a non-rotating portion, a packer disposed within the non-rotating portion, a retainer ring radially disposed about the packer, and an annular piston radially disposed about the packer and aligned with the retainer ring. In another aspect, the invention provides a method of releasing a packer from a drilling head, comprising disengaging a retainer from a packer and removing a packer from the drilling head while retaining rotating portions of the drilling head with the drilling head. In another aspect, the invention provides a method of adjusting bearing pressure in a drilling head, comprising rotating a rotating portion relative to a non-rotating portion using at least one bearing disposed therebetween, pressurizing a fluid port in said non-rotating portion fluidicly connected to a bearing piston with a fluid, and actuating the bearing piston toward a moveable bearing race adjacent a remaining portion of the bearing. 


   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof 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  is a schematic side view of a typical drilling rig. 
       FIG. 2  is a schematic cross sectional view of a prior art blow out preventer. 
       FIG. 3  is a schematic cross sectional view of another prior art blow out preventer. 
       FIG. 4  is a schematic partial view of a drilling rig using the present invention. 
       FIG. 5  is a schematic cross sectional view of one embodiment of a rotary drilling head, shown in split  FIGS. 5A and 5B . 
       FIG. 6  is a schematic top view of the embodiment of  FIG. 5 . 
       FIG. 7  is a schematic side view of a drive bushing. 
       FIG. 8  is a schematic cross sectional view of another embodiment of the invention, shown in split  FIGS. 8A and 8B . 
       FIG. 9  is a cross sectional schematic view of another embodiment of the drilling head. 
       FIG. 10  is a cross sectional schematic view of another embodiment of the drilling head. 
       FIG. 11  is a partial cross sectional schematic of a subsea wellbore with a drilling platform disposed thereover. 
       FIG. 12  is a cross sectional schematic view of another embodiment of the drilling head. 
   


   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
   The present invention generally provides a removal system for a packer in a rotary drilling head and an adjustable loading system for bearing loads in the rotary drilling head. Preferably, the removal of the packer and adjustment of the bearing load can be done remotely through a hydraulic, pneumatic and/or electrical system external to the packer or bearing such as through a system mounted on the drilling head or a system distant from the drilling head itself. 
     FIG. 4  is a schematic partial view of a drilling rig  100  using the present invention. A stack  102  of flanged connections is located above the well  104  and connects one or more blow out preventers. An annular BOP  106  is disposed above the well in fluidic communication with the well drilling and production fluids. In the case of excess pressure in the well, the BOP will close the well and annular spaces  108  surrounding the drill string  110  in the well. Under normal conditions, the mud used to lubricate equipment in the well and flush drill shavings from a drill bit (not shown) is pumped through the outflow line  112  to mud pits (not shown). A rotary drilling head  114 , also referred to as a rotary BOP, is mounted above the outflow line  112  and assists in sealing the drill string  110  as the drill string slides axially through the internal rotary drilling head surfaces, i.e., axially with respect to the longitudinal axis of the drill string. A kelly  116  is attached to the drill string  110  and is inserted into the rotary drilling head  114 . The kelly  116  is typically hexagonal or square to transmit torque to rotatable portions of the drilling head  114  so that the rotatable portions rotate in conjunction with rotation of the drill string  110  and the kelly  116 . A power unit  118  is mounted in proximity to the stack  102  and provides power to operate the rotary drilling head  114  and associated system equipment on the rig  10  through hydraulic, pneumatic, and/or electrical circuitry. The power unit  118  can be mounted on a skid  120  for portability. The power unit  118  typically houses pumps, valving, motors, and reservoirs for the system within an enclosure  122 . In the embodiment shown, the system is simplified in that two pressure lines  124  travel to the rotary drilling head  112  and two pressure lines  126  travel to a control unit  128  mounted on the drilling platform  130 . The control unit  128  houses valving, meters, gauges, and other equipment and is designed to control the pressure and flow from the power unit  118 . While a hydraulic system is preferred, it is to be understood other systems such as pneumatic systems using gases, electrical systems and combinations thereof can also be used. 
     FIG. 5  shows a schematic cross sectional view of one embodiment of the drilling head  114 . The right side of the figure shows the drilling head  114  in an unengaged state without a drill string  110  disposed therethrough and the left side shows the drilling head  114  engaged with a drill string  110  axially disposed therethrough. The main components of the drilling head  114  generally include an annular lower housing  132 , an annular bearing housing  134 , an annular upper housing  136 , an annular packer  138 , an annular drive bushing  140 , a releasing element, such as a retainer ring  182 , and an actuator for the releasing element, such as a main piston  188 , and a lower body  142 . 
   The lower housing  132  of the drilling head  114  is attached to an annular lower body  142  which can be attached to the stack  102 , referred to in  FIG. 4 , through a flange  150  or other connection. Preferably, pins  144  are radially oriented about the circumference of the lower body  142  and engage recesses  146  on the lower housing  132 . The recesses  146  preferably are conically tapered to receive and engage a taper  145  on the pins  144 . The recesses  146  provide alignment between the lower housing  132  and the lower body  142 . The pins  144  can also engage a radial groove extending around the lower housing, instead of individual recesses. The lower body  142  can also include the main overflow line  148 . 
   The bearing housing  134  is attached to the lower housing  132  and engages an upper bearing  152  and a lower bearing  154 . A cap  156  is attached to the upper surfaces of the bearing housing and seals the upper bearing  152  from dust and other contaminants. The cap  156  preferably has a plurality of lifting eyes  158 . An inner housing  160  is disposed radially inward from the upper and lower bearings  152 ,  154  and engages the upper and lower bearings. The upper housing  136  is attached to the upper portion of the inner housing  160  and supports the packer  138  disposed inwardly of the upper housing  136 . 
   The packer  138  includes a mandrel  206   a , which is an annular elongated metallic body, and an element  206   b  coupled to the mandrel, known as a “stripper rubber”. The element  206   b  can be non-pressure assisted, as shown in  FIG. 5 , or pressure assisted, as shown in  FIG. 8 . The tubing string is inserted through the packer  138  and into the wellbore. The packer  138  is disposed inwardly from the upper housing  136  on an upper end of the packer and inwardly from the inner housing  160  on a lower end of the packer. The packer  138  is fixed in relative rotational alignment to the upper housing  136  and inner housing  160  by lugs  139  integral to or otherwise connected to the packer  138  that are disposed in axial slots  137  in the upper housing  136 . The element  206   b  is made of elastomeric material such as rubber and is attached to the mandrel  206   a , such as by molding, and forms a sealing surface for the drill string  110  as the drill string axially slides through the rotary drilling head  114 . In an unengaged state, the element  206   b  preferably is molded to be biased toward the centerline of the packer  138 . The element  206   b  can deflect as the drill string  110  and shoulders  208  at joints on the drill string  110  pass therethrough. The drive bushing  140  is disposed radially inward from the packer  138  and engages tabs  162  on the packer  138  with slots  163 . A drive bushing  140  is not used in some instances when the drill string  110  is rotated without a kelly  116 . In such instances, the packer  138  preferably has sufficient frictional contact with the drill string  110  to rotate with the drill string without using the drive bushing  140 . 
   The upper bearing  152  comprises an inner race  172 , an outer race  174 , and a series of rollers  176  annularly disposed inside the bearing housing  134  and outside the inner housing  160 . The outer race  174  engages the bearing housing  134  and the inner race  172  engages the inner housing  160 . The upper bearing  152  is pre-loaded by a bearing actuator, such as an annular bearing piston  178 , disposed in an annular cavity  180  in the bearing housing  134  axially adjacent the outer race  174  of the upper bearing  152 . The bearing piston  178  engages the outer race  174  with pressure exerted from a hydraulic or pneumatic fluid applied to the bearing cavity  180  below the bearing piston  178  to move the outer race toward the rollers  176  and pre-load the upper bearing  152  and lower bearing  154 . The pre-loading force can be monitored and maintained or selectively changed remotely without removing the bearings and associated housings by maintaining or adjusting the fluid pressure exerted on the bearing piston  178 . Alternatively, a bias member (not shown) such as a spring can be used separately or in combination with the fluid pressure to pre-load the bearing. Such movements of the bearing race is deemed “remote” herein, in that the bearing race is moved by an additional member. 
   The lower bearing  154  likewise comprises an inner race  164 , an outer race  166 , and a series of rollers  168  annularly disposed inside the lower housing  132 . The outer race  166  engages a bottom portion of the bearing housing  134  and the inner race  164  engages an outside portion of the inner housing  160 . A lower bearing retainer  170  is threadably attached to the inner housing  160 . When the bearing piston  178  moves upwardly and engages the outer race  174  of the upper bearing  152 , the resulting force on the outer race  174  is transmitted through the upper bearing  152  to the inner housing  160  and tends to move the inner housing  160  upwardly. The inner race  164  on the lower bearing  154  moves upwardly with the inner housing  160  and exerts force on the rollers  168  of the lower bearing  154  to pre-load the lower bearing. 
   The combination of the lower and upper bearings allows axial and radial loads to be supported in the drilling head  114  as the drill string  110  is inserted therethrough and rotates the packer  138 , the inner housing  160 , the inner races  164 ,  172  and the rollers  168 ,  176 . The outer races  166 ,  174 , bearing housing  134 , and lower housing  132  typically do not rotate. Lubricating fluid, such as hydraulic fluid, preferably is pumped through each bearing  152 ,  154  to lubricate and wash contaminants from the bearings. 
   An annular retainer ring  182  is disposed in an annular ring cavity  184  formed between an upper portion of the inner housing  160  and a lower portion of the upper housing  136 . The retainer ring  182  is radially aligned with an annular groove  186  on the outside of the packer  138  and inward of the retainer ring  182 . Preferably, the retainer ring is “C-shaped” and can be compressed to a smaller diameter for engagement with the groove  186 . Preferably, in a radially uncompressed state, the retainer ring  182  does not engage the groove  186  and the packer can be removed. An annular main piston  188  is disposed in a lower cavity  190  in the inner housing  160  and protrudes into the ring cavity  184 . The main piston  188  is axially aligned in an offset manner from the retainer ring  182  by an amount sufficient to engage a tapered surface  192  on the outside periphery of the retainer ring  182  with a corresponding tapered surface  194  on the inside periphery of the main piston  188 . The main piston is connected to various fluid passageways for actuation. The retainer ring  182  has a cross section sufficient to engage the groove  186  and still protrude into the ring cavity  184  so as to limit the axial travel of the packer  138  by abutting the lower end of the upper housing  136  and the upper end of the main piston  188 . A bias member (not shown) can be disposed axially adjacent the end of the main piston  188  that is distant from the retainer ring  182  to provide an axial force to the main piston and pre-load the piston against the retainer ring. The bias member can be, for example, a spring, pressurized diaphragm or tubular member, or other biasing elements. An upper cavity  191  is disposed between the main piston  188  and the upper housing  136  and is separate from the ring cavity  184 . An indicator pin  202  is disposed in the upper housing  136 . On the lower end of the indicator pin  202 , the pin engages the upper end of the main piston  188 . The upper end of the indicator pin  202  is disposed outside the upper housing  136 , when the main piston  188  is disposed upwardly in the ring cavity  184 . 
   An assortment of seals are used between the various elements described herein, such as wiper seals and O-rings, known to those with ordinary skill in the art. For instance, each piston preferably has an inner and outer seal to allow fluid pressure to build up and force the piston in the direction of the force. Likewise, where fluid passes between the various housings such as the pistons, seals can be used to seal the joints and retain the fluid from leaking. 
     FIG. 6  is a schematic top view of the drilling head shown in  FIG. 5 . The bearing housing  134  is circumferentially bolted to the lower housing (not shown) and the cap  156  is circumferentially bolted to the bearing housing  134 . The upper housing  136  is disposed radially inward of the cap  156  and is circumferentially bolted to the inner housing (not shown). The upper housing  136  includes two slots  137  in which lugs  139  on the packer  138  are inserted to maintain the relative rotational position of the packer  138  with the upper housing  136  and inner housing  160 . The drive bushing  140  is disposed radially inward of the packer  138 , is supported axially by the packer, and is radially fixed in position relative to the packer  138  by the slots  163  on the drive bushing when engaged with the tabs  162  on the packer  138 . 
     FIG. 7  is a schematic side view of the drive bushing  140 . The drive bushing  140  is designed to mate in two or more symmetrical portions  250 ,  252 . Each symmetrical portion includes a tab  254  and a slot  256  on opposing sides formed between two or more flanges  258 ,  260 , and bolt holes  262  through which bolts  264  are inserted through adjacent symmetrical portions, including the tabs and slots, to retain the symmetrical portions together. The bolts holes  262  are disposed axially, so that if the bolts  264  should be loosened in operation, the bolts would remain in place and the symmetrical portions  250 ,  252  be retained together in contrast to a typical radial alignment for the bolts in which loose bolts could be thrown away from an assembled bushing by centrifugal force. The drive bushing  140  has an annular tapered surface  266  to mate with a corresponding tapered surface in the packer  138 , referenced in  FIG. 6 , and assist in securing the drive bushing axially in the packer. 
   In operation, referencing  FIGS. 4–7 , a crane  26  lifts the rotary drilling head  114  onto the stack  102  and the lower body  142  is attached to the stack with bolts in the flange  150 . One or more pins  144  in the lower body  142  engage the recesses  146  to secure both the axial and rotational positions of remaining portions of the drilling head  114 , i.e., those portions of the drilling head detachable from the lower body. Alternatively, the lower body  142  can be attached separately to the stack  102  and the remaining portions of the drilling head  114  attached to the lower body  142  with pins  144 . Fluid, such as hydraulic fluid(s) or pneumatic gas(es), is pumped into the drilling head  114  by the power unit  118  and controlled by the control unit  128 . To engage the retainer ring  182  with the groove  186 , the fluid is pumped into the lower cavity  190  and axially displaces the main piston  188  into engagement with the retainer ring  182  to force the ring radially inward. The engaged position of the retainer ring  182  with the groove  186  is shown on the left side of  FIG. 5 . The force exerted between the tapers  192 ,  194  compresses the retainer ring  182  radially inward to engage the groove  186 . The indicator pin  202  is pushed outward from the upper housing  136  by the travel of the main piston  188  to indicate the groove  186  is engaged. An assembly (not shown) can be bolted to the upper housing  136  to manually force the indicator pin  202  back into the upper housing  136 , thereby forcing the main piston  188  away from the retainer ring  182  to manually release the packer  138  if desired. Thus, the packer  138 , as a first rotating portion, is releasably retained in the drilling head  114  by the retainer ring  182 . Additionally, the fluid pressure can be maintained on the piston  188  even while the inner housing  160  and upper housing  136  rotate within the bearing housing  134  by the several seals, such as wiper seals and O-rings, located between non-rotating portions and other rotating portions of the drilling head, such as between the bearing housing  134  and the upper housing  136  or the inner housing  160 . 
   A drill string  110 , drilling bit (not shown), and a kelly  116  are assembled and inserted through the drive bushing  140  and the packer  138 . The element  206   b  deflects radially outward as the drill string  110  is axially forced through the packer  138  and effects a seal about the periphery of the drill string. The kelly  116  is rotated which rotates the drill string, the drilling bit, and rotating components of the drilling head  114  for drilling a well. 
   When the packer  138  and particularly the element  206   b  is to be replaced, the retainer ring  182  expands radially outward to disengage the packer  138  from the drilling head  114 . Fluid is forced into the upper cavity  191  and axially forces the main piston  188  away from the retainer ring  182 , whereupon the retainer ring decompresses radially outward and disengages the groove  186 , thereby releasing the packer from the non-rotating portions and other rotating portions. A pipe joint on the drill string  110  is separated and the upper portion of the drill string is removed from the drilling head  114 . Because of the relatively light weight of the packer  138  compared to the assembly of rotating components and especially compared to the entire drilling head  114 , neither the crane  26  nor special equipment may be needed to connect to the packer  138  and pull it from the drilling head  114 . The crane  26  may simply lift the drill string  110  and the element  206   b  can rest on the pipe shoulder  208  and pull the packer  138  with the drill string  110 . The bearings  152 ,  154 , upper housing  136 , inner housing  160 , cap  156 , bearing housing  134 , and lower housing  132 , all can remain attached to the lower body  142 . 
   The packer  138  may be reinserted into the drilling head  114  in the opposite manner. The packer  138  is placed on the drilling head  114  and rotated until the lugs  139  on the packer  138  are aligned with the slots  137  in the upper housing  136  and the packer then slides axially into position. The drive bushing  140 , if not already installed, is placed over the packer  138 , the slots  163  are aligned with the tabs  162  on the packer  138 , and the drive bushing is slid into position. The fluid pressure in the upper cavity  191  can be released and the fluid pressure in the lower cavity  190  forces the main piston  188  into engagement with the retainer ring  182 . The retainer ring  182  compresses radially inward and engages the groove  186 . The packer is thus secured and operations can be resumed. 
     FIG. 8  is a schematic cross sectional view of another embodiment of the drilling head. The embodiment shows two primary changes where one is to the packer  210  and the other to the manner in which the remaining portions of the drilling head  114  are retained to the lower body  142 . Any of the changes could be used with other embodiments and is not limited to the embodiment shown. In this embodiment, the other portions of the drilling head  114  remain substantially unchanged. The packer  210  includes a mandrel  212   a  and a pressure assisted element  212   b  is disposed radially inward from the mandrel and is axially bound by the mandrel on either end of the pressure assisted element. The pressure assisted element  212   b  is shown in an unengaged mode on the right side of the centerline in  FIG. 8  and in an engaged mode with a drill string  110  on the left side of  FIG. 8 . A port(s)  214  is disposed through the sidewall of the packer  210  radially outward from the pressure assisted element  212   b  and is connected to fluid passageway(s)  213  leading to the power unit  118  and control unit  128 , referenced in  FIG. 4 . A drill string  110  having a shoulder  208  at each typical pipe joint is axially disposed through the drilling head  114  on the left side of the centerline. A cavity  216  in the engaged position shown on the left side of  FIG. 8  is formed when fluid pressure forces the pressure assisted element  212   b  toward the drill string  110 . The pressure assisted element assists in conforming the packer to variations in size and/or shape of different portions of the drill string, such as shoulder  208 , as the drill string is inserted through the drilling head. 
   An annular lower housing  218  is attached to an annular piston housing  220  disposed below the lower housing. An annular lower main piston  222  is disposed radially inward of the piston housing  220  and is housed in a lower ring cavity  224  formed between the lower end of the lower housing  218 , the inner periphery of the piston housing  220 , and a shoulder  226  of the piston housing  220 . A lower retainer ring  228  is disposed in the lower ring cavity  224  similar to the retainer ring  182 . The lower main piston  222  is axially aligned with the lower retainer ring  228  in an offset manner and engages the lower retainer ring  228  between tapered surfaces  230 ,  232 . A lower groove  234  is formed on the outside circumference of the lower body  142  and is radially aligned with the lower retainer ring  228 . A wear ring  236  is disposed axially adjacent and below the lower retainer ring  228 . An upper cavity  238  is formed between the lower main piston  222  and a lower end of the lower housing  218 . A lower cavity  240  is formed between the lower main piston  222  and the piston housing  220 . A lower indicator pin  242 , similar to the indicator pin  202 , referenced in  FIG. 5 , is axially disposed in the piston housing  220  and aligned with the lower main piston  222 . 
   In operation, the remaining portions of the drilling head  114  can be inserted over the lower body  142 . Fluid is forced into the upper cavity  238  and applies pressure to the lower main piston  222 . The lower main piston slides axially and engages the lower retainer ring  228  between the tapered surfaces  230 ,  232 , thereby radially compressing the lower retainer ring  228  into the groove  234 . The remaining portions of the drilling head  114  are thus secured to the lower body  142 . The lower main piston  222  forces the lower indicator pin  242  axially outward from the piston housing  220 , indicating an engaged mode. If the remaining portions of the drilling head  114  should need removal from the lower body  142 , fluid is forced into the lower cavity  240 , thereby axially displacing the lower main piston  222  away from the lower retainer ring  228 . The lower retainer ring  228  radially decompresses, disengages from the groove  234  on the lower body  142  and releases the remaining portions of the drilling head  114  for removal. 
   Furthermore, in operation, a drill string is inserted through the drilling head  114  and axially slides by the packer  210 . Fluid is transported through the port(s)  214  and expands the cavity  216  which in turn forces the pressure assisted element  212   b  to radially compress against the drill string  110 . The amount of radial compression on the drill string can be controlled such as by regulating the pressure in the cavity  216 . 
     FIG. 9  is a cross sectional schematic view of another embodiment of the drilling head  114 . A lower body  280  generally houses the various rotating and non-rotating elements described in reference to the embodiment shown in  FIG. 5 . The lower body  280  includes an attachment member, such as a flange  282 , which defines connecting holes  286  for bolts or other fasteners to pass therethrough into a mating flange (not shown) such as a flange disposed at the top of a well head casing. The lower body  280  also includes an attachment member, such as a flange  284 , which defines connecting holes  288  for bolts or other fasteners to pass therethrough for connecting the lower body  280  to a mating flange  294  on an upper body  292 . The upper body  292  is mounted to the lower body  280  in a sealing relationship with the flanges  284 ,  294  and covers the various rotating and non-rotating members housed by the lower body  280 . The upper body also includes an upper flange  296  which defines holes  300  for bolts or other fasteners to pass therethrough into a mating flange (not shown), such as a flange disposed at the bottom of a casing extending downward from a drilling platform. The flange  284  of the lower body defines a lower body seal groove  290  and the flange  294  of the upper body defines an upper body seal groove  302 . The seal grooves  290 ,  302  are sized and spaced in a cooperative relationship so that a seal  303  can be disposed therebetween to effect a seal between the flanges. Generally, the upper body and the lower body form an enclosure in connection with adjoining structure for protecting the bearings and packer of the drilling head from a radially external medium such as corrosive fluids, dirt, and other contaminates. 
   In general, various rotating and non-rotating members of the drilling head are disposed in a cavity  293  formed by the upper body  292  and lower body  280 . For example, the bearing housing  134  is mounted to the lower housing  280  by a fastening member  307 , such as one or more bolts, snap rings or other known fastening members, disposed within the cavity  293 . The fastening member  307  can also be an arrangement similar to the retainer ring  182  and main piston  188 , shown in  FIGS. 5 and 8 , that could engage the bearing housing  134  to the lower body  280  or the upper body  292 . The piston could be remotely actuated so that the bearing housing could be selectively fastened or released. A remote release or fastening could be particularly useful in remote locations such as in subsea applications. A packer  304 , similar to the packer  138 , is disposed within the drilling head  114  inward of an annular upper housing  136 . The packer  304  may extend upward to the elevation of the annular upper housing  136 . The packer  304  includes a mandrel  306  and an element  308 , similar to the mandrel  206   a  and element  206   b , respectively, shown in  FIG. 5 . The packer  304  is at least partially disposed in a cavity formed between the upper body  292  and the lower body  280 . 
     FIG. 10  is a cross sectional schematic view of another embodiment of the drilling head  114 , having members similar to those described in the embodiment shown in  FIG. 8 . The lower body  280  includes a flange  282  which defines connecting holes  286  for bolts or other fasteners to pass therethrough into a mating flange (not shown) on an adjacent structure. The lower body  280  also includes a flange  284  which defines connecting holes  288  for bolts or other fasteners to pass therethrough for connecting the lower body  280  to a mating flange  294  on an upper body  292 . The upper body  292  is mounted to the lower body  280  in a sealing relationship with the flanges  284 ,  294  and covers the various rotating and non-rotating members housed by the lower body  280 . The upper body also includes an upper flange  296  which defines holes  300  for bolts or other fasteners to pass therethrough into a mating flange (not shown) on an adjacent structure. The flange  284  of the lower body defines a lower body seal groove  290  and the flange  294  of the upper body defines an upper body seal groove  302 . The seal grooves  290 ,  302  are sized and spaced in a cooperative relationship so that a seal  303  can be disposed therebetween to effect a seal between the flanges. 
   A packer  310  is disposed annularly within the annular upper housing  136 . The packer  310  includes a mandrel  312  and a pressure assisted element  314  that is disposed radially inward from the mandrel. The pressure assisted element  314  is axially bound by the mandrel on either end of the element. The pressure assisted element  314  is shown in an engaged mode with a drill string  110  that is axially disposed through the drilling head  114 . A port(s)  214  is disposed through the sidewall of the packer  310  radially outward from the pressure assisted element  314  and is fluidicly connected to a fluid pressure source. A cavity  216  is formed when fluid pressure forces the pressure assisted element  314  toward the drill string  110 . The pressure assisted element  314  assists in conforming the packer  310  to variations in size and/or shape of different portions of the drill string  110  as the drill string is inserted through the drilling head. The pressure assisted element  314  seals against the drill string  110  and allows differences in pressure between a first zone  316  and a second zone  318  for independent control of the pressures in the zones as described below. 
     FIG. 11  is a partial cross sectional schematic of a subsea wellbore  330  with a drilling platform  324  disposed thereover. The flanged embodiments shown in  FIGS. 9 and 10  can be used in such an application. A casing  326  is suspended from the drilling platform  324  and extends a distance from the drilling platform to near the sea floor  328 . A drill string  110  is disposed within the casing so that an annular space  344  is formed therebetween. A flange  340  is connected to the lower end of the casing. A flanged drilling head  114  is sealingly connected to the flange  340  with a flange  296  disposed on the top surfaces of the drilling head. Similarly, a flange  286  disposed on the bottom surfaces of the drilling head  114  is sealingly connected with a flange  342  disposed on top of the wellbore  330 . 
   As the casing increases in depth, the weight of the water increases the pressure on the external surface of the casing. A sufficiently high pressure can distort or collapse the casing. A counteracting pressure within the annular space  344  in the casing can offset the effects of the external water pressure and minimize pressure differences. For example, the pressure differences can be minimized by flowing a fluid of similar density as sea water into the annular space to lessen the pressure gradient between the internal and external surfaces of the casing. 
   However, pressures necessary to drill into a subsea formation in the wellbore  330  may necessitate different pressures than those pressures required to offset the water pressure on the casing  326 . A drilling head  114 , such as the embodiment shown in  FIG. 10 , can be mounted between the casing and the wellbore. The pressure assisted packer  310  engages the drill string  110  and creates a first zone  316  above the packer  310  and a second zone  318  below the packer. A first set of pressures can be controlled in the first zone  316  to offset the pressures from the water as the casing increases in depth. A second set of pressures can be controlled in the second zone  318  to enable effective drilling into the various formations and production zones. 
     FIG. 12  is a cross sectional schematic view of another embodiment of the drilling head  114 , having members similar to those described in the embodiment shown in  FIGS. 9 and 10 . An upper body  350  is coupled to a lower body  280  with flanges  284 ,  294  or other coupling members. Alternatively, the upper body  350  and the lower body  280  can be made as a unit with or without the flanges. A bearing housing  362 , similar to bearing housing  134  shown in  FIGS. 9 and 10 , is removably coupled to the upper body  350  and/or the lower body  280 . An upper housing  136  is disposed radially inward of the bearing housing  362 . A packer  310  is disposed radially inward of the upper housing  136 . A throat  352  of the upper body  350  is sized to allow the bearing housing  362  and related members to be disconnected from the upper or lower body and be retrieved therethrough. 
   One system for coupling the bearing housing  362  is similar to the system of a fastening member such as a retainer ring  186  and a piston  188 , shown in FIGS.  5  and  8 – 10 . As an example, the upper body  350  can include an annular piston cavity  354  in which a piston  356  is disposed and sealably engaged with a wall of the piston cavity. A first port  366  can be used to flow fluid, such as hydraulic fluid or pneumatic gases, to and from a first portion  354   a  of the piston cavity to actuate the piston  356 . Another port  368  can be fluidicly coupled to a second portion  354   b  of the piston cavity that is formed on an opposite portion of the piston  356  from the first portion  354   a  of the piston cavity. Lines or hoses, such as line  369  coupled to port  368 , can deliver fluid to one or both of the ports. Line  369  can be disposed external to the upper body  350  and can be used to remotely actuate the piston. A retainer ring  358  is disposed adjacent an end of the piston  356  and in one embodiment is biased radially outward from the bearing housing  362 . The retainer ring  358  retains the bearing housing as one example of an assembly to the one or more of the surrounding bodies. Other assemblies, whether including one member or a plurality of members, can be retained by the retainer ring  358 . Mating surfaces between the retainer ring  358  and the piston  356  are preferably tapered to allow the piston to force the ring radially inward as the piston moves downward. A corresponding groove  360  formed in the bearing housing  362  is adapted to receive the retainer ring  358  when the retainer ring is biased inward toward the bearing housing. At least one seal  364  can be disposed between the bearing housing  362  and an adjacent surface of the upper body  350  to seal drilling fluids from portions of the piston cavity  354 . 
   The embodiment shown in  FIG. 12  could also include other packers and related members, such as shown in  FIG. 9 . Further, other members of the drilling head  114  could be coupled to the upper or lower bodies in lieu of or in addition to the bearing housing  362 . 
   In operation, fluid can flow through the port  366  into the first portion  354   a  of the piston cavity  354  to force the piston  356  toward the retainer ring  358 . For example, fluid disposed in the throat  352  can flow through the port  366  into the piston cavity  354  to bias the piston  356  downward during operation. The piston  356  contacts the retainer ring  358  and forces the retainer ring radially inward toward the groove  360  on the bearing housing  362 . The retainer ring  358  engages the groove  360  and retains the bearing housing and related components to the upper body  350 . To release the bearing housing  362  from the upper body  350 , the piston  356  retracts from engagement with the retainer ring  358 . For example, fluid flown through line  369 , through port  368  and into the second portion  354   b  of the piston cavity  354  can force the piston  356  upward and override the fluid pressure acting on the top of the piston through port  366 . The retainer ring  358  expands radially outward and away from the bearing housing  362 . A drill string  110  or other member disposed downhole can be used to lift the bearing housing  362  from the upper body to the surface of the well or drilling platform (not shown). 
   Variations in the orientation of the packer, bearings, retainer ring, rotating spindle assembly, and other system components are possible. For example, the retainer ring can be biased radially inward or outward. The pistons can be annular or a series of cylindrical pistons disposed about the drilling head. Various portions of the drilling head can be coupled to the upper and/or lower bodies besides the particular members described herein. Other variations are possible and contemplated by the present invention. Further, while the embodiments have discussed drilling heads, the invention can be used to advantage on other tools. Additionally, all movements and positions, such as “above”, “top”, “below”, “bottom”, “side”, “lower” and “upper” described herein are relative to positions of objects such as the packer, bearings, and retainer ring. Further, terms, such as “coupling”, “engaging”, “surrounding” and variations thereof, are intended to encompass direct and indirect “coupling”, “engaging” and “surrounding” and so forth. For example, a retainer ring can be coupled directly to the packer or can be coupled to the packer indirectly through an intermediate member and fall within the scope of the disclosure. Accordingly, it is contemplated by the present invention to orient any or all of the components to achieve the desired movement of components in the drilling head assembly. 
   While the foregoing is directed to the preferred embodiment 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.