Patent Abstract:
A drive head for a wellhead, the drive head comprising: a rod drive; a pressure chamber; and a rod receiving part connected to the rod drive and enclosed within the pressure chamber. A method comprising: pressurizing a chamber mounted to a wellhead, in which the chamber encloses an upper end of a rod extending from the wellhead; and driving the rod using a rod receiving part enclosed within the chamber.

Full Description:
TECHNICAL FIELD 
       [0001]    This document relates to a drive head for a wellhead. 
       BACKGROUND 
       [0002]    Stuffing boxes are used in the oilfield to form a seal between the wellhead and a well tubular passing through the wellhead, in order to prevent leakage of wellbore fluids between the wellhead and the piping. Stuffing boxes may be used in a variety of applications, for example production with pump-jacks, and inserting or removing coiled tubing. Stuffing boxes may incorporate a tubular shaft mounted for rotation in the housing for forming a stationary seal with the piping in order to rotate with the piping. The tubular shaft in turn dynamically seals with the stuffing box housing. Designs of this type of stuffing box can be seen in the following patents: U.S. Pat. No. 7,044,217 and CA 2,350,047. in other designs, the stuffing box may instead form a dynamic seal directly against the piping without incorporating a rotating tubular shaft. Stuffing boxes may be used for rotating or reciprocating pumps. 
         [0003]    Drive heads are used in tandem with stuffing boxes. In some cases the drive head sits above the stuffing box. In other cases the stuffing box is incorporated into the drive head or sits above the drive head, for example in  FIG. 3  of U.S. Pat. No. 7,044,217. 
         [0004]    Leakage of crude oil from a stuffing box is common in some applications, due to a variety of reasons including abrasive particles present in crude oil and poor alignment between the wellhead and stuffing box. Leakage costs oil companies money in service time, down-time and environmental clean-up. Leakage is especially a problem in heavy crude oil wells in which oil may be produced from semi-consolidated sand formations where loose sand is readily transported to the stuffing box by the viscosity of the crude oil. Costs associated with stuffing box failures are some of the highest maintenance costs on many wells. 
       SUMMARY 
       [0005]    A drive head for a wellhead is disclosed, the drive head comprising: a rod drive; a pressure chamber; and a rod receiving part connected to the rod drive and enclosed within the pressure chamber. 
         [0006]    A method is disclosed comprising: pressurizing a chamber mounted to a wellhead, in which the chamber encloses an upper end of a rod extending from the wellhead; and driving the rod using a rod receiving part enclosed within the chamber. 
         [0007]    A drive head for a wellhead is disclosed, the drive head comprising: a stationary housing with a base, one or more sidewalk, and a top wall; and a rod drive connected to the stationary housing; the stationary housing defining a pressure chamber extending from an opening in the base to the top wall, in which the pressure chamber forms a dead end for a rod. 
         [0008]    In various embodiments, there may be included any one or more of the following features: The rod drive is mounted within the pressure chamber. The rod drive is a hydraulic motor. The pressure chamber forms a casing for the hydraulic motor. A case drain is connected between the casing and a hydraulic fluid return line, which is also connected to the hydraulic motor. A rod is connected to the rod receiving part, the rod having an upper end enclosed within the pressure chamber. The pressure chamber is pressurized above a wellhead pressure. The pressure chamber is above 10 psi. The pressure chamber is above 100 psi. At least part of a top wall of the pressure vessel is removable. The rod receiving part further comprises a tubular shaft mounted for rotation, the tubular shaft having a threaded rod end coupler. The drive head is adapted for production of wellbore fluids. The drive head is adapted for a progressing cavity pump application. The rod is connected to a downhole pump. Downhole fluids are produced from the wellhead. 
         [0009]    These and other aspects of the device and method are se out in the claims, which are incorporated here by reference. 
     
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         [0010]    Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which: 
           [0011]      FIG. 1A  is a view of a progressing cavity pump oil well installation in an earth formation for production with a typical drive head, wellhead frame and stuffing box; 
           [0012]      FIG. 1B  is a view similar to the upper end of  FIG. 1  but illustrating a conventional drive head with an integrated stuffing box extending from the bottom end of the drive head; 
           [0013]      FIG. 2  is a side elevation section view of a drive head for a wellhead; 
           [0014]      FIG. 3  is a side elevation view of the drive head of  FIG. 2 ; 
           [0015]      FIG. 4  is a perspective view of the drive head of  FIG. 2 ; and 
           [0016]      FIG. 5  is a hydraulic fluid schematic for operating the drive head of  FIG. 2 . 
           [0017]      FIG. 6  is a side elevation view of a drive head incorporating an electric rod drive. 
       
    
    
     DETAILED DESCRIPTION 
       [0018]    Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims. 
         [0019]      FIG. 1A  illustrates a known progressing cavity pump installation  10 . The installation  10  includes a typical progressing cavity pump drive head  12 , a wellhead frame  14 , a stuffing box  16 , an electric motor  18 , and a belt and sheave drive system  20 , all mounted on a flow tee  22 . The flow tee is shown with a blowout preventer  24  which is, in turn, mounted on a wellhead  25 . The drive head  12  supports and drives a drive shaft  26 , generally known as a “polished rod”. The polished rod is supported and rotated by means of a polish rod clamp  28 , which engages an output shaft  30  of the drive head by means of milled slots (not shown) in both parts. The clamp  28  may prevent the polished rod from falling through the drive head and stuffing box, and may allow the drive head to support the axial weight of the polished rod. Wellhead frame  14  may be open sided in order to expose polished rod  26  to allow a service crew to install a safety clamp on the polished rod and then perform maintenance work on stuffing box  16 . Polished rod  26  rotationally drives a drive string  32 , sometimes referred to as a sucker rod, which, in turn, drives a progressing cavity pump  34  located at the bottom of the installation to produce well fluids to the surface through the wellhead. 
         [0020]      FIG. 1B  illustrates a typical progressing cavity pump drive head  36  with an integral stuffing box  38  mounted on the bottom of the drive head and corresponding to the portion of the installation in  FIG. 1A  that is above the dotted and dashed line  40 . An advantage of this type of drive head is that, since the main drive head shaft is already supported with hearings, stuffing box seals can be placed around the main shaft, thus improving alignment and eliminating contact between the stuffing box rotary seals and the polished rod. This style of drive head may also reduce the height of the installation because there is no wellhead frame, and also may reduce cost because there are fewer parts since the stuffing box is integrated with the drive head. A disadvantage is that the drive head must be removed to do maintenance work on the stuffing box. In addition, a stuffing box is still required above the drive head  36  to dynamically seal off the rod  30  from the ambient environment. Surface drive heads for progressing cavity pumps require a stuffing box to seal crude oil from leaking onto the ground where the polished rod passes from the crude oil passage in the wellhead to the drive head. 
         [0021]    Referring to  FIG. 2 , a drive head  50  is illustrated having a rod drive  52 , a pressure chamber  54 , and a rod receiving part  56 . Rod receiving part  56  is connected to the rod drive  52  and enclosed within the pressure chamber  54 . A rod  58  may be connected to the rod receiving part  56 . In use an upper end  60  of the rod  58  is enclosed within the pressure chamber  54 . Thus, the pressure chamber  54  forms a dead end for rod  58 . Because part  56  and upper end  60  are enclosed within the pressure chamber  54  during use, there is no need for a dynamic seal, such as provided by a stuffing box, between the rod  58  and the outer ambient environment  66 . 
         [0022]    The lack of a dynamic seal between the outer ambient environment  66  and the pressure chamber  54  is advantageous because it allows pressure chamber  54  to be pressurized to a much greater extent than if chamber  54  terminated in a dynamic seal to the ambient environment  66  as is the case when a regular stuffing box is used. This is because static seals can be pressurized to a greater extent without leaking than dynamic seals. In fact, pressure chamber  54  may be pressurized above standard case pressures, for example if chamber  54  is pressurized to above 10 psi, above 100 psi, or even as high as above 500 psi in some cases. The pressure of chamber  54  may be equal or lower than pressure line  120  (FIG.  5 ) pressure if a hydraulic motor  53  is used, described further below. The relatively high pressure of chamber  54  works against wellhead fluid pressure and across the one or more seals  62  between the chamber  54  and the well  64 , reducing the amount of wellhead fluids that undesirably cross seals  62  and enter the chamber  54 . Chamber  54  may be pressurized above a wellhead pressure. By contrast with dynamic seals of a traditional stuffing box open to atmosphere  66 , if bottom seal  59  of drive head  50  fails, pressurized fluid leaks into the well  64  and not into the atmosphere  66 . 
         [0023]    Referring to  FIGS. 2 ,  3 , and  4 , chamber  54  may be defined by a stationary housing  68  made up of one or more sidewalk  70 , a top wall  72 , and a base  74 . Sidewall  70  is illustrated as being cylindrical, although other shapes may be used for sidewall  70 . Top wall  72  may include an annular top cap  78  connected, for example threaded, to a top hat  80  for enclosing the upper end  60  of the rod  58  ( FIG. 2 ). At least part of top wall  72  may be removable, for example to allow a convenient method of servicing components within the chamber  54 . In other cases an interior  82  of chamber  54  is accessible via suitable means, such as a window in sidewall  70 . Chamber  54  may include one or more lifting lugs  76  for transporting the drive head  50 . Base  74  may house one or more seals  62  for sealing against rod  58  in use. Base  74  may connect to wellhead  6 . 4  directly or indirectly as shown, for example through a bottom spool  84 . other cases drive head  50  may be mounted upon a flow tee (not shown). Chamber  54  may extend from an opening  81  in the base  74  to the top wall  72 . 
         [0024]    The pressurization advantages of chamber  54  are still realized if a stuffing box is used below chamber  54 . Bottom spool  84  is a form of stuffing box, although bottom spool  84  does not seal between wellhead fluid and outer ambient environment  66  like a normal stuffing box does. Thus, there is no dynamic seal on spool  84  between environment  66  and wellhead fluid. Bottom spool  84  may include one or more mechanisms for axially compressing seals  62 . For example, a biasing device such as spring  86  may be positioned between seals  62  and a ring  87  positioned between spool  84  and base  74 . Compression of spring  86  caused by bringing base  74  and spool  84  closer together increases sealing by seals  62  against rod  58 . other cases one or more bolts  88  may be mounted in spool  84  to provide lateral force into a wedge piston  90  whose tapered lateral end  92  contacts a wedge ring  93  that transfers lateral force into axial compression against seals  62 . Seals  62  positioned below bottom seals  59  of base  74  are advantageously used with drive head  50  in that they allow servicing of the drive head  50  without allowing leakage of well fluids. To service drive head  50 , a user may remove top hat  80 , coupler  96 , and top wall  72  in some cases, and remove a part or all of motor  53 . Poly seals  51  prevent excess production fluids from leaking past and contaminating the pressurized chamber  54 . 
         [0025]    The rod receiving part  56  may comprise a tubular shaft  94  or rotating sleeve mounted for rotation. The tubular shaft  94  may have a threaded rod end coupler  96 , such as a hex driver with a PR thread as shown. One or more bearings or bushings (not shown) may be used to align the shaft  94  and facilitate smooth rotation. Shaft  94  may be connected to be driven by rod drive  52  by a suitable mechanism such as meshing with a lateral extension  100  of shaft  94 . Other mechanisms of torque transfer between rod drive  52  and rod  58  may be used. 
         [0026]    The rod drive  52  may be connected to the chamber  54 , for example mounted within the pressure chamber  54  as shown. The rod drive  52  may be a suitable motor, such as a hydraulic motor  53 . The pressure vessel  54  may form a casing  55  for the hydraulic motor  53 . A case drain  98  may be connected to the casing  55 . Hydraulic pressure and return lines may connect to a pressure line input  102  and a return tine input  104  formed in housing  68  ( FIGS. 3 and 4 ). A relief valve  106  may be located on case drain  98  ( FIGS. 2-4 ). One or more fluid channels  111  may extend laterally from for example above top seal  57  of base  74 , in order to provide a leak path to allow fluid leaking from hydraulic motor  53  to preferentially collect in casing  55 . Fluid channel  111  also prevents crude oil from wellhead  64  from being forced into hydraulic motor  53 , where such oil may over pressure and damage motor  53 . Case drain  98  pressure may be set at a higher pressure than production fluid, so if hydraulic fluid is lost it goes downhole. If enough hydraulic fluid is lost, motor  53  will shut down. 
         [0027]    Referring to  FIGS. 2 ,  3 , and  5 , a method of operation of hydraulic motor  53  will be described. Fluid from one or more hydraulic tanks  108  is pumped via pump  110  through a pressure line  112  ( FIG. 5 ). A return tank  109  may also be connected to pump  110 . A retarder  114  with a restriction  116  on bypass loop  117  may be located on line  112  to prevent or reduce backspin upon pump shut off. On pump shut off, the backspin generated by rod  58  and exerted upon motor  53  causes reverse flow of hydraulic fluid in line  112 , which cannot pass through check valve  118 , and instead flows through restriction  116  at a reduced flow rate, if at all. Restriction  116  acts as a break on backspin, and prevents the rod from damaging itself via unconstrained freewheeling. Restriction  116  also prevents or reduces the chance that hydraulic fluid contaminated with wellhead fluid is sent back to pump  110  or tank  108 . 
         [0028]    Pressure line  112  ( FIG. 5 ) sends hydraulic fluid to motor  53  through pressure input  102  ( FIG. 3 ), where the pressure of the hydraulic fluid is used to perform work by rotating rod  58  ( FIG. 2 ). Rod  58  may connect to a downhole pump  34  for producing well fluids. Chamber  54  is pressurized by the motor case drain  98 , which is choked off via relief valve  106 . Once the work is accomplished by a given unit of fluid volume, the unit of fluid volume returns through return input  104  ( FIG. 3 ) and into return line  120  ( FIG. 5 ). Return line  120  cleans contaminants such as sand particles from return fluid by passing return fluid through a filter  122 , a check valve  124 . After filtration, the return fluid is deposited for re-use or further cleaning in a tank  126 , which may be the same as one of tanks  108  or  109  ( FIG. 5 ). If filter  122  becomes clogged, or in other events where fluid pressure in line  120  climbs beyond a predetermined level, a bypass valve  128  controlled by pressure from line  127  of line  120  bypasses return fluid past the filter  122  and into tank  126 . 
         [0029]    Motor  53  also includes case drain  98  between the casing  55  ( FIG. 2 ) and hydraulic fluid return line  120  ( FIG. 5 ). The case drain line  98  has a line  123  that passes into a valve  130  that feeds case fluid back into return line  120  for recycling and re-use during normal pump  110  operation. Valve  130  is controlled by pressure from line  131  sent from pressure line  112 , so that the system operates as shown when pump  110  is not operating. Thus, free flow across valve  130  is allowed until the pressure line  112  pressure builds to a sufficient level to close valve  130 . When the pump  110  is shut off or pressure in line  112  reduces below a predetermined pressure, valve  130  opens to allow fluid connection between case drain  98  and return line  120  to reduce case pressure, Thus, during operation, the pressure in chamber  54  is allowed to grow to a predetermined pressure. In the event that valve  130  malfunctions and doesn&#39;t open, or another event causes an undesirable pressure increase in line  98  indicating a pressure state in pressure chamber  54  above a predetermined pressure, pressure from line  98  causes relief valve  106  to open, allowing case drain pressure to pass through bypass line  121  of line  98  and into return line  120  through check valve  132 . Running the case drain  98  to the return line  120  eliminates the need for an additional hose that would otherwise be used to keep the casing  55  at a low enough pressure to prevent dynamic seal leakage. 
         [0030]    Drive head  50  may be used for production of wellbore fluids, such as production in a progressing cavity pumping application as shown. Drive head  50  may be adapted to be retrofitted into a wellhead  39 . In other cases drive head  50  may be adapted for an integral application, for example in the style shown in  FIG. 1B . Connections between components may be accomplished by suitable mechanisms such as bolting, threading, clamping, and retaining. Although described above for a rotating rod embodiment, drive head  52  may be used in a reciprocating rod application as well. 
         [0031]    It should be understood that various other components may be incorporated into drive head  50 . For example, various seals  89  may be provided at points between rod  58  and housing  68 , or between other components. Similarly, o-rings, gaskets, packing and other components may be used. 
         [0032]    Referring to  FIG. 2 , the one or more seals  62  may comprise packing  63 , packing  67 , or other suitable seals such as lip seals  65  or poly seals  51 . Seals  62  may be mechanical or non-mechanical seals. Different packing may be used for packing  63  and  67 . One or more rings such as brass rings may be located on either side of seals  62 . O-rings  89  or other suitable gaskets may be used throughout drive head  50 . In general, where the word seal is mentioned in this document, one or more seals may be provided to effectively operate as a single seal, for example observed in the stacking of packing seals  65 . 
         [0033]    It should be understood that various other components such as blow out preventers may be provided with the drive head  50  for wellhead applications to be carried out. Drive head  50  may incorporate a lubrication system (not shown) for lubricating various components, such as the one or more seals  62 . Various components discussed herein may include sub-components, such as the plural sleeves that thread together to make up the top wall  72  of  FIG. 2 . As well, components that are shown as being separate may be combined integrally, for example base  74  and side wall  70 . Connections between components, or the mounting of one component to another, may be done through intermediate parts. Figures may not be drawn to scale, and may have dimensions exaggerated for the purpose of illustration. Drive head  50  may have no rotating parts or dynamic seals on the exterior of drive head  50 . Non hydraulic drives may be used, for example if an electric motor is used as shown in  FIG. 6 , although a pressurization system may be required to pressurize chamber  54 . 
         [0034]    In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite article “a” before a claim feature does not exclude more than one of the feature being present. Each one of the individual features described here may he used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the

Technology Classification (CPC): 4