Patent Document

RELATED APPLICATIONS  
       [0001]    Applicant claims priority to the application described herein through a United States provisional patent application titled “Drill Cuttings Injection System,” having U.S. Patent Application Serial No. 60/340,056, which was filed on Dec. 10, 2001, and which is incorporated herein by reference in its entirety. 
     
    
     
       BACKGROUND OF THE INVENTION  
         [0002]    1. Technical Field  
           [0003]    This invention relates in general to the communication from a casing annulus to the outer wellhead housing, and more particularly to the monitoring of casing annulus pressure, the injection of drill cuttings generated from drilling a subsea well, or the injection of a heavy fluid into the casing annulus to reduce the casing annulus pressure.  
           [0004]    2. Background of the Invention  
           [0005]    A subsea well that is capable of producing oil or gas will have an outer or low pressure wellhead housing secured to a string of conductor pipe that extends some short depth into the well. An inner or high pressure wellhead housing lands in the outer wellhead housing. The high pressure wellhead housing is secured to an outer string of casing, which extends through the conductor pipe to a deeper depth into the well. Depending on the particular conditions of the geological strata above the target zone (typically, either an oil or gas producing zone or a fluid injection zone), one or more additional casing strings will extend through the outer string of casing to increasing depths in the well until the well is to the final depth.  
           [0006]    The last string of casing extends into the well to the final depth, this being the production casing. The strings of casing between the first casing and the production casing are intermediate casing strings. When each string of casing is hung in the wellhead housing, a cement slurry is flowed through the inside of the casing, out of the bottom of the casing, and back up the outside of the casing to a predetermined point.  
           [0007]    Virtually all operators monitor pressure of producing wells in the annulus flow passage between the strings of casings. Normally there should be no pressure in the annulus between each string of casing because the annular space between each string of casing and the next larger string of casing is ordinarily cemented at its lower end and sealed with a packoff. If pressure increased within an annulus between the strings of casings, it would indicate that a leak exists in one of the strings of casing. The leak could be from several places. Regardless of where the leak is coming from, pressure build up in the annulus could collapse a portion of the production casing, compromising the structural and pressure integrity of the well. For this reason, operators monitor the pressure in the annulus between the production casing and the next larger string of casing in a well.  
           [0008]    It is advantageous to be able to have a way to efficiently communicate with a casing inside of a high pressure or inner wellhead housing. Operators need the capability to pump down a heavy fluid into the casing annulus of a well in order to reduce casing annulus pressure. It is also desirous for operators to monitor an annular pressure between the high pressure wellhead housing and a string of casing positioned inside of the wellhead housing. Furthermore, operators also desire an efficient way to inject “cuttings” into the casing annulus of the well.  
           [0009]    When a subsea well is drilled, cuttings, which are small chips and pieces of various earth formations, will be circulated upward in the drilling mud to the drilling vessel. These cuttings are separated from the drilling mud and the drilling mud is pumped back into the well, maintaining continuous circulation while drilling. The cuttings in the past have been dumped back into the sea or conveyed to a disposal site on land.  
           [0010]    While such practice is acceptable for use with water based drilling muds, oil based drilling muds have advantages in some earth formations. The cuttings would be contaminated with the oil, which would result in pollution if dumped back into the sea. As a result, environmental regulations now prohibit the dumping into the sea of cuttings produced from oil based muds.  
           [0011]    There have been various proposals to dispose of the oil based cuttings. One proposal is to inject the cuttings back into a well. The well could be the well being drilled, or the well could be an adjacent subsea well. Various proposals in patents suggest pumping the cuttings down an annulus between two sets of casing into an annular space in the well that has a porous formation. The cuttings would be ground up into a slurry and injected into the porous earth formation. Subsequently, the well receiving the injected cuttings would be completed into a production well.  
           [0012]    U.S. Pat. No. 5,085,277, Feb. 4, 1992, Hans P. Hopper, shows equipment for injecting cuttings into an annulus surrounding casing. The equipment utilizes piping through the template or guidebase and through ports in specially constructed inner and outer wellhead housings. Orientation of the inner wellhead housing with the outer wellhead housing is required to align the ports.  
           [0013]    U.S. Pat. No. 5,662,129, Sep. 2, 1997, Stanley Hosie, shows equipment with specially manufactured extensions attached between the lower portions of both the inner and outer wellhead housings and the upper portions of the casings hanging therefrom. Each of the extensions have ports that must align in order for the cuttings to communicate through the inner and outer wellhead housings to an annular space inside of the inner wellhead housing. A swivel joint on the extension of the inner wellhead housing supports the casing hanging therefrom while allowing rotation of the inner casing above the swivel joint for aligning ports extending through each of the inner and outer wellhead housings.  
           [0014]    U.S. Pat. No. 6,394,194, May 28, 2002, Michael Queen et al., shows equipment with a port formed in a collar that aligned with a passage in an inner wellhead housing above the outer wellhead housing. Having the communication port in the collar positioned above the outer wellhead housing was one way to remove the necessity of aligning a port on the inner wellhead housing with a port on the outer wellhead housing. The collar, however, had to be aligned with the passageway opening to the outer surface of the inner wellhead housing, and then the injector system had to align with the port formed in the collar. This necessitated the use of two brackets that had to land around the inner wellhead housing after the inner wellhead housing had landed.  
           [0015]    U.S. Pat. No. 5,366,017, Nov. 22, 1994, Robert K. Voss, Jr., and U.S. Pat. No. 5,544,707, Aug. 13, 1996, Hans P. Hopper et al., both show equipment for monitoring casing annulus pressure. The inventions disclosed in both of these patents show equipment that has the casing annulus pressure communicating to a point above the high pressure wellhead housing on the exterior of a tree assembly that has landed on the high pressure wellhead housing. Various systems have been utilized in order to prevent the casing annulus from communicating until the tree assembly lands on the high pressure wellhead housing. With the equipment shown in the Hopper and Voss patents, it is difficult to monitor the casing annulus pressure before the tree assembly lands.  
           [0016]    U.S. Pat. No. 6,186,239, Feb. 13, 2001, Noel A. Monjure et al., shows equipment for circulating heavy fluids into an annulus formed between casing strings in order to relieve casing pressure due to leaks. The invention disclosed in the Monjure &#39;239 patent shows injecting heavy fluids into a well by lowering a flexible hose into an annulus between casing strings. Heavy fluids are pumped through the hose and into the annulus for well fluid displacement when the pressure builds up in the annulus between casing strings due to leaks in the casing.  
           [0017]    Many of the above-mentioned assemblies require an injection assembly to be connected before a riser is attached to the wellhead assembly. Furthermore, some of the assemblies communicate with the casing annulus through passages in both the inner and outer wellhead housings. This requires that alignment of the inner and outer wellhead housings, which can add to the expense of the assembly in either time and cost of manufacture, or time and cost of installation.  
         SUMMARY OF THE INVENTION  
         [0018]    A subsea wellhead assembly has the capabilities of communicating from the outer surface of an inner wellhead housing, or inner wellhead tubular member, to a casing annulus located between the inner wellhead housing and a string of casing supported by a casing hanger within the inner wellhead housing. The subsea wellhead assembly has a connector that is adapted to be attached to the lower end of a riser that connects the riser to the well. The inner wellhead housing has a grooved profile on its exterior surface. When the connector attaches to the well, the connector connects to the grooved profile on the inner wellhead housing. The casing annulus is in fluid communication with the exterior of the inner wellhead housing through a passage extending through the inner wellhead housing. A communication port extending through a side of the connector registers with the passage so that the connector is in fluid communication with the casing annulus.  
           [0019]    Pressure within the casing annulus can be monitored at the connector through the communication port and the passage. A line can be connected to the communication port for delivering a fluid into the casing annulus. The fluid can be a slurry of injection cuttings. The fluid may also be water or some other heavy fluid.  
           [0020]    In the preferred embodiment, a seal ring slidingly engages the exterior of the inner wellhead housing to open and close the passage. The seal ring closes the passage when the connector is not attached to the inner wellhead housing. The seal ring is actuated when the connector attaches to the inner wellhead housing. The passage is open after the connector actuates the seal ring when attaching to the inner wellhead housing. A piston actuates a locking member in the connector to matingly engage the grooves on the inner wellhead housing. The piston also actuates the connector to push the seal ring, so the passage is open, while the locking members are engaging the grooves.  
           [0021]    In the preferred embodiment, the inner wellhead housing also has an upper channel extending from the exterior of the inner wellhead housing to its bore. The casing hanger has a lower channel extending from its outer surface to the casing annulus. The upper and lower channels register with each other such that the casing annulus is also in fluid communication with the exterior of the inner wellhead housing through the upper and lower channels. A connector channel extending through a side of the connector is in fluid communication with the upper channel. The fluid can be injected into the casing annulus through the connector, upper, and lower, channels. Casing annulus pressure can also be monitored at the connector through the connector, upper, and lower channels. In the preferred embodiment, a casing hanger tubular member extends from the casing hanger to a predetermined depth in the casing annulus. The casing hanger tubular member is in fluid communication with the lower channel. Fluid can be delivered into the casing annulus at the predetermined depth.  
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0022]    [0022]FIG. 1 is a cross section of the injection and monitoring system with the annular ring engaged by the drill cuttings injector assembly and shown in an open position.  
         [0023]    [0023]FIG. 2 is a cross section of the injection and monitoring system with the annular ring shown in a closed position.  
         [0024]    [0024]FIG. 3 is an enlarged view of a portion of the injection and monitoring system shown in FIG. 1.  
         [0025]    [0025]FIG. 4 is a further enlarged view of a portion of the injection and monitoring system shown in FIG. 1. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0026]    Referring to FIGS. 1 and 2, a subsea well injection and monitoring system  10 , for injecting drill cuttings, heavy fluids, and monitoring casing annulus pressure, is shown. A wellhead receptacle or guide base  12  is located on the sea floor. A low pressure wellhead housing  14 , or outer wellhead tubular member, is landed within wellhead receptacle  12 . The low pressure wellhead housing  14  has an upper rim  16 . Conductor pipe  15  extends downward from low pressure wellhead housing  14  to a selected depth in the well. A high pressure wellhead housing  18 , inner wellhead tubular member, is landed within the low pressure wellhead housing  14 . High pressure wellhead housing  18  supports outer casing  19 , which extends downward from a lower end of high pressure wellhead housing  18  to a second and deeper depth in the well.  
         [0027]    A casing hanger  21  secured to the upper end of an inner string of casing  22  is landed within high pressure wellhead housing  18  and sealed by a packoff or casing hanger seal  24 . Casing  22  extends into the well to a greater depth than outer casing  19  and is cemented in place. An annulus  28  is defined between inner casing  22  and outer casing  19 . Only a portion of annulus  28  is filled with cement, leaving an upper portion for injecting either a slurry of cuttings from another well into porous earth formations, or heavy fluids to help maintain the integrity of the casing annulus.  
         [0028]    One or more passages  20  are formed within the wall of high pressure wellhead housing  18 . Each passage  20  extends parallel to the axis of wellhead housing  18  and has an upper end  20   a  in communication with an exterior surface of high pressure wellhead housing  18 . Upper end  20   a  extends above upper rim  16  of low pressure wellhead housing  14  and above packoff  24  of casing hanger  21 . Passage  20  has a lower end  20   b  in communication with an inner surface of high pressure wellhead housing  18  and with annulus  28 . In the preferred embodiment, passages  20  may be used for injecting cuttings. In another embodiment, a pressure transducer (not shown) can also be placed in fluid communication with upper end  20   a  in a manner know to those skilled in the art, so that passage  20  can also be used for monitoring casing annulus pressure. Lower end  20   b  extends below packoff  24  of casing hanger  21 . A check valve  23  may be located in passage  20  to prevent back flow of cuttings slurry.  
         [0029]    Referring also to FIGS. 3 and 4, one or more wash passages  25 , or upper channels, extend through high pressure wellhead housing  18 . Wash passage  25  is parallel to and does not intersect passage  20 . Wash passage  25  has an upper end on the exterior of high pressure wellhead housing  18  above packoff  24  and low pressure wellhead housing rim  16 . The lower end of wash passage  25  is in the bore of high pressure wellhead housing  18 . In the preferred embodiment, packoff  24  has upper and lower sealing portions and the lower end of wash passage  25  is located between the upper and lower sealing portions. As shown in FIG. 4, the lower seal portion is an elastomeric seal  33  located within a metal body. The upper portion comprises a metal-to-metal U-shaped seal  34 . Seal  34  is energized by an axially movable energizing ring  35 . A hole  36  extends through the body of packoff  24  between seals  33  and  34 . Hole  36  communicates wash passage  25  in high pressure wellhead housing  18  with a wash passage  26  in casing hanger  21 . A check valve  29  is preferably located in wash passage  25  to prevent back flow of slurry.  
         [0030]    Wash passage  26 , or lower channel, extends downward within the wall of casing hanger  21  parallel to the axis of casing hanger  21 . A tubing  27 , or casing hanger tubular member, is secured to the lower end of wash passage  26 . Tubing  27  is strapped to the exterior of casing  22  within casing annulus  28  and extends to a selected depth above the level of cement in casing annulus  28 . In the preferred embodiment, tubing  27  allows a liquid to be pumped from the surface to a lower portion of annulus  28 . Alternatively, a pressure transducer (not shown) can also be placed in fluid communication with wash passage  26  in a manner know to those skilled in the art, so that passages  25 ,  26  can also be used for monitoring casing annulus pressure.  
         [0031]    A seal ring  32  is mounted to the exterior of high pressure wellhead housing  18  above low pressure wellhead housing  14 . Seal ring  32  is axially movable, permitting it to be shifted upward and downward, thus closing and opening the upper end  20   b  of passage  20  as wells as wash passage  25 . FIGS. 1 and 3 show ring  32  in a lower open position while FIG. 2 shows ring  32  in an upper closed position.  
         [0032]    A connector assembly  37  is lowered on a riser. Connector assembly  37  is typically used for injecting fluids into casing annulus  28 , but may also be used for monitoring the pressure in annulus  28 . Connector assembly  37  has a body that engages ring  32  when landing on the upper end of high pressure wellhead housing  18 . Upon engagement, ring  32  is shifted downward to the open position. A latch  39  is mounted to connector  37  for engaging ring  32 . Typically, latch  39  has a plurality of teeth that engage with a plurality of grooves located on ring  32 . When connector  37  is moved back upward, as shown in FIG. 2, latch  39  draws ring  32  back upward to the closed position.  
         [0033]    Connector  37  has locking elements  40  that move radially inward and connect to grooves formed on the mandrel or upper end of high pressure wellhead housing  18 . At least one axially movable piston  42  moves locking elements  40  inward. Other types of connections between connector  37  and high pressure wellhead housing  18  are feasible. A line  38  extends downward to connector  37  for delivering a slurry of cuttings. Line  38  may extend alongside or within the riser. Line  38  registers with a passage  44  extending through connector  37  to an inner diameter portion. The inner diameter of the body of connector  37  slides sealingly over ring  32 , and the outlet of passage  44  locates above ring  32 . An annular chamber is created above ring  32  that communicates the outlet of passage  44  with upper end  20   a  of passage  20 . A wash passage  46 , or connector channel, extends through connector  37  into alignment with wash passage  25  in high pressure wellhead housing  18 . In the one embodiment, a pressure transducer (not shown) would typically be placed on connector  37 , in communication with passage  44 , in order to have a pressure transducer in fluid communication with passage  20  for monitoring casing annulus pressure. In another embodiment, a pressure transducer (not shown) would typically be placed on connector  37 , in communication with passage  46 , in order to have a pressure transducer in fluid communication with wash passages  25 ,  26  for monitoring casing annulus pressure.  
         [0034]    In operation, a wellhead receptacle  12  is located on the sea floor. After drilling the well to a first depth, low pressure wellhead housing  14  and conductor  15  are lowered into the receptacle  12 . An operator then drills through conductor  15  to a selected depth. High pressure wellhead housing  18  is lowered with outer casing  19  and cemented in place. Ring  32  will be in the upper closed position shown in FIG. 2. The well is drilled to an even greater depth. Casing hanger  21  is lowered with casing  22  and cemented in place, leaving an annulus  28  between casings  19  and  22 . Tubing  27  is strapped to casing  22  during the installation of casing  22 . Connector  37  is lowered onto high pressure wellhead housing  18  and secured by locking elements  40 . As it lands, it will push ring  32  downward to the open position, shown in FIGS. 1 and 3.  
         [0035]    When it is desired to dispose of cuttings from another well, the cuttings are mixed in a slurry and pumped down line  38 . The cuttings pass through passages  44  and  20  and flow into casing annulus  28 . At the same time, water may be injected through passages  46 ,  25  and  26  and down tubing  27 . The water flows upward in annulus  28  to prevent bridging of the cuttings flowing downward. The connector assembly  37  can be lifted off the high pressure wellhead housing  18  when no further cuttings are desired to be deposited. As seen in FIG. 2 when connector assembly  37  is lifted off of high pressure wellhead housing  18 , connector assembly  37  engages latch  39  on the ring  32  and moves ring  32  up to the closed position. Latch  39  disengages from ring  32  as connector  37  is retrieved.  
         [0036]    Further modifications and alternative embodiments of various aspects of the invention will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein or in the steps or in the sequence of steps of the methods described herein without departing from the spirit and the scope of the invention as described.

Technology Category: 0