Abstract:
A novel rotary table is secured to the top of a well&#39;s BOP simplifying the making up of sectional tubing joints used in some aspects of operations with coiled tubing. The rotary table comprises top a bottom stationary housing affixed to the BOP, a top housing supported on the bottom housing by an annular bearing, a split clamp to transferring the weight of the tubing to the top housing and seals between the top and bottom housings and between the top housing and the tubing. More preferably, a coiled tubing rig is provided having a frame, a tiltable mast, an injector reel, a tubing straightener and a jib crane in combination with the rotary table for increased functionality including drilling surface hole using coiled tubing. The mast tilts between two positions, either aligning coiled tubing and injector with the BOP or aligning a jib crane and tubing elevators for manipulating sectional tubing including BHA onto and through the rotary table.

Description:
FIELD OF THE INVENTION 
     The present invention relates to apparatus and a process for drilling a well. More specifically, addition of a rotary table to the wellhead in combination with a coiled tubing rig and modifications thereto enable drilling a borehole in the earth including borehole adjacent the surface. 
     BACKGROUND OF THE INVENTION 
     The general background relating to coiled tubing injector units is described in U.S. Pat. Nos. 5,839,514 and 4,673,035 to Gipson which are incorporated herein by reference for all purposes. 
     Coiled tubing has been a useful apparatus in oil field operations due to the speed at which a tool can be injected and tripped out of a well bore (round trip). Coiled tubing is supplied on a spool. An injector at the wellhead is used to grip and control the tubing for injection and withdrawal at the well. Accordingly, it is known to connect a bottom hole assembly (“BHA”) to the bottom of the coiled tubing and run it into the well bore using the injector. A BHA may include measuring and sampling tools, each being sectional and which are threaded together in series. A BHA may also include drill collars for weight. Further, use of downhole motors and coiled tubing became more popular when drilling deviated wells as it made more sense to limit drilling rotation to the bit and not the entire string which must flex through a turn. 
     As stated, coiled tubing has more recently become a contender in the drilling industry, due to the potential to significantly speed drilling and reduce drilling costs through the use of continuous tubing. The most significant cost saving factors include the reduced pipe handling time, pipe joint makeup time, and reduced leakage risks. 
     In spite of the significant potential cost savings through the use of coiled tubing, there are certain aspects of the associated apparatus and process which have limited its application to drilling. 
     Coiled tubing has been unable to cope with all stages of the drilling and have required the assistance of conventional rigs for handling jointed tubing for certain aspects of drilling a well. For example, coiled tubing has not been successfully used to drill surface hole due in part to a lack of bit weight at surface or shallow depths, lack of control over the coiled tubing&#39;s residual bend and the generally uneven strata at surface, such as glacial residue. Typically then, a separate and conventional rig is required to drill surface hole, place surface casing, cement and then drill the vertical well portion. Thereafter, coiled tubing is used to re-enter and deepen the hole a relatively short distance (i.e., coiled tube drilling only the last, smallest and shallow portion). Generally, coiled tubing is used to re-enter the vertical hole and drill a relatively short and deviated or horizontal lateral portion. 
     Further, after drilling, a separate rig is brought in to run in the sectional and tubular production casing. 
     Several restrictions are placed on the use of coiled tubing. One restriction is related to the inability to rotate coiled tubing. A conventional rotary drilling rig rotates the entire drill string from the surface for rotating a rotary drill bit downhole. The continuous coiled tubing is supplied from a spool at surface and cannot be rotated. Accordingly, a BHA including a downhole motor and drill bit is connected to the bottom end of the coiled tubing. Further, the BHA is typically threaded together and thereby results in a laborious threading of the multiple components separate from the coiled tubing. It is sometimes desirable to increase the weight on the bit early in the drilling and thus a few lengths of conventional drill collars might be to threaded onto the BHA. 
     The injector is typically located at the wellhead and must be set aside to permit the larger diameter BHA to be placed through the wellhead and into the hole. Further, when running in, the wellhead injector tends to inject tubing which has residual bend therein. A residual bend can result in added contact and unnecessary forces on the walls of the hole, resulting in increased frictional drag and an off-centered position of the tubing within the hole. Occasionally the coiled tubing wads up in the hole (like pushing a rope through a tube) and cannot be injected any further downhole or ever reach total depth. 
     Therefore, in practice, the above problems result in the need for multiple rigs; a conventional rig to drill and place surface casing, coiled tubing for the remainder of the drilling and a conventional rig again to place the production casing. Besides the duplicity for much of the equipment and personnel, such as pumping equipment, much time is lost in assembling the BHA. 
     For example, a conventional rig may take two days to spud in, drill surface casing, and cement the casing. The crew manually makes up a BHA, requiring in the order of 6 hours. A separate crane is generally employed to lower the BHA through the wellhead, the BHA being supported temporarily on slips. If weight is required, one or more drill collars are manually threaded into the BHA supported at the wellhead. Finally, a prior art coiled tubing rig is set up and connected to the BHA, injected down the surface casing and drilling may then begin. After drilling, the crane is again employed to withdraw the BHA from the well. Lastly a conventional rig is brought in again to place the jointed production casing. 
     Coiled tubing rigs, while faster, have a much higher capital cost and operating cost. The repeated plastic deformation of the coiled tube means it must be replaced often to avoid failure. Further, the rig incorporates spools, related equipment and pumps. The pumps and operating costs are greater due to the relatively small diameter of the coiled tubing, requires greater fluid horsepower to deliver mud to the downhole motor. 
     Thus, it is an objective to use the coiled tubing rig for a greater portion of the on-site operations, reduce the on-site time generally and improve the drilling process. 
     SUMMARY OF THE INVENTION 
     A novel combination of components has resulted in a novel coiled tubing rig capable of superior handling and drilling. 
     Through the addition of a novel rotary table to the well site, preferably secured to the top of the wellhead or BOP, sectional tubular components can be readily handled and the capabilities of a coiled tubing rig are markedly enhanced, now being able to easily make up BHA and yet retain the convenience and speed of a coiled tubing rig. 
     In a preferred embodiment of the invention, a coiled tubing rig is provided having a frame, a mast, an injector reel, a tubing straightener and a jib crane. In combination with the rotary table, the time required for spudding in and drilling 1100 meters of well is only about ½ to ⅓ of the time of a jointed tubing rig. Specifically, this is accomplished by tilting the mast between two positions, one with the coiled tubing injector aligned with the wellhead and a second with the injector out of alignment so as to permit the jib crane to align with the wellhead. The jib crane handles long lengths of BHA, threaded tubular components or other jointed sections between the wellhead and coiled tubing. The jib manipulates the BHA onto and through the rotary table. The rotary table supports the jointed BHA sections so that they are easily rotated while being supported so as to quickly make up threaded joints. Tilting the injector back over the wellhead, the BHA is attached to the coiled tubing so as to commence drilling. Preferably, the injector is mounted high above the wellhead so aid in the BHA handling. The straightener delivers straight coiled tubing which is directed through a supporting stabilizer. Even more preferably, adding power tongs to the jib crane and coupling that with the tilting capability of the mast enables jointed production casing to be quickly run in without need for another rig on site. 
     As a result of the above combination, the preferred coiled tubing rig is able to drill surface hole, place jointed surface casing, quickly make up jointed BHA, drill the well, withdraw the coiled tubing, quickly remove the BHA, and place jointed production casing. 
     Therefore, in a broad apparatus aspect of the invention, a rotary table is provided for the supported rotation of BHA or other sectional components at the wellhead comprising: 
     a bottom stationary housing affixed to the top of the wellhead; 
     a top rotational housing; 
     means such as slips or a split clamp for transferring the weight of the BHA to the top housing; 
     an annular bearing installed between the top and bottom housings; and 
     seals between the top and bottom housings and between the top housing and the BHA. 
     Preferably the seal is an inflatable packer. 
     In another broad apparatus aspect of the invention, a coiled tubing rig, implemented in combination with the rotary table, creates a hybrid apparatus capable of superior site set-up, handling and functionality. More particularly, the apparatus comprises: 
     a coiled tubing rig having a frame and a mast normally aligned over a wellhead, an injector located in the mast and a tubing straightener positioned between the injector and the wellhead; 
     a rotary table affixed to the well head; 
     a jib crane mounted atop the mast; and 
     means for pivoting the mast between two positions, a first position where the mast, injector and straightener are aligned with the wellhead for injection and withdrawing of coiled tubing, and a second position with the mast pivoted out of alignment from the wellhead so that the jib crane can align sectional tubing with the wellhead and be supported therefrom and be made up on the rotary table. 
     Preferably a stabilizer tube extends between the injector and the wellhead. 
     In another broad aspect of the invention, a method is provided comprising the steps of: 
     providing a rotary table over the well, preferably secured to a wellhead; 
     supporting tubular sections on the rotary table to enable rotation of adjacent sections for making up a drilling assembly including a downhole motor and drill bit; 
     aligning a coiled tubing injector over the drilling assembly; 
     rotating the drilling assembly to make up to the coiled tubing; and 
     drilling the well through the rotary table. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a side elevation view of the coiled tubing aspect of the apparatus, illustrated in a road transport mode, and constructed according to an embodiment of the present invention; 
     FIG. 2 is an overall side elevation view of the apparatus according to FIG. 1, arranged over a well bore in an injecting/drilling position; 
     FIG. 3 is a side elevation view of the apparatus according to FIG. 2, wherein the mast is tilted out of alignment from the wellhead for handing lengths of tubing and BHA; 
     FIG. 4 is a partial side and exploded view of the rotary table with a flow tee incorporated therein. The bottom housing is flanged to the BOP and the top housing is shown separated from the bottom housing; 
     FIG. 5 is an upward perspective sectional view of jointed sectional tubing passing through the rotary table&#39;s top housing. The tubing is fitted with a split clamp, both of which are ready to set down on the top housing for rotary capability; 
     FIGS. 6 a - 6   d  are a variety of upward perspective views of components of the top housing. Specifically, 
     FIG. 6 a  is a view of the top housing; 
     FIG. 6 b  is a sectional view of the top housing, according to FIG. 6 a , illustrating, in dotted lines, installation of the ring bearing; 
     FIG. 6 c  is an exploded view of the three components of the ring bearing; 
     FIG. 6 d  is a view of an elastomeric seal for installation into the entrance of the top housing for sealing about a jointed section passing therethrough; 
     FIGS. 7 a  and  7   b  are views of the top housing. Specifically, 
     FIG. 7 a  is a side sectional view of the top housing with the ring bearing installed; and 
     FIG. 7 b  is a top view of the top housing according to FIG. 7 a.   
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     Having reference to FIG. 1, a coiled tubing injector is mounted on a mobile deck  11  such as a truck or trailer or on a separate frame (not shown) which could be slid or lifted onto or off of a truck or trailer. 
     As disclosed in U.S. Pat. No. 5,839,514 to Gipson, a coiled tubing storage reel or spool  12  is mounted on a cradle  13 , and coiled tubing  14  is stored thereon. The cradle  13  is attached to a traversing mechanism which allows the cradle to be reciprocated perpendicularly to the axis of the deck  11 . 
     An injector reel  20  is rotatably attached to the distal end  21  of boom arm or mast  22 . Mast  22  is attached at hinge member  23  to mast riser  24 . Mast riser  24  is attached to the back end  25  of deck  11 . 
     Having reference to FIG. 2, the injector reel  20  is further provided with a drive mechanism  30  which includes a hydraulic drive motor  31 , a drive chain linkage  32 , and sprocket assembly  33  extending circumferentially around the injector reel  20 . 
     Reel support frame  34  also extends circumferentially around reel  20  and supports a straightener assembly  35  and a hold down assembly  40 . 
     Hold-down assembly  40  consists of a multiplicity of separate hold down mechanism  41 . Twenty hold-down mechanisms  41  are mounted around a portion of the circumference of the injector reel  20  to exert pressure against the coiled tubing  14  over more than 90 degree of the circumference of the injector reel  20 . 
     The straightener  35  applies unequal pressure against the coiled tubing  14 , plastically altering the curve of the tubing so that it leaves the straightener  35  as linear tubing, without any residual curve. 
     A hydraulically activated elevating work floor  50  is movable along the working length of the mast  22  and particularly adjusts for variable classes of Blow-out Preventor (BOP)  51  which, when fitted to the well and wellhead can vary up to 2 meters in final installed height. 
     As shown in FIG. 2, in a first position, the mast  22  is raised by a mast lift cylinder  52 , pivoting about hinge  23 , to a tubing injection position generally perpendicular to the deck  11 . Swing locks  53  (one on each side of mast  22 ) are latched to secure the mast  22  and injector reel  20  in the uplift position. In the first injecting position, coiled tubing  14  extends from the storage spool  12  up and over the injector reel  20 . The hold-down assembly  40  extends around a portion of the circumference of the injector reel  20  to exert pressure on the coiled tubing  14  as it is straightened and injected into the well or returned to the spool  12 . 
     When the embodiment is in the injecting position, tubing  14  exits the injector reel  20  generally perpendicular to the ground. In cases where the drilling has progressed past the surface casing stage, when tubing  14  exits the injector reel  20  it is generally aligned with the BOP  51 . 
     A telescoping tubing stabilizer  70  has an upper section  71  and a lower section  72 . The stabilizer  70  extends between the straightener assembly  35  and the BOP  51  at the wellhead. The function of the stabilizer  70  is to ensure that the coiled tubing  22  does not bend or excessively flex as it is being injected. 
     A swivel bushing  60  supports the upper section  71  of the telescoping tubular stabilizer  70  where it connects to the straightener assembly  35 . A misaligning union  61  between the stabilizer&#39;s upper section  71  and the straightener  35  allows for misalignment of the stabilizer with respect to the BOP  51  with no adverse effects. A hydraulic winch  62  mounted on the mast  22  is used to collapse and extend the stabilizer  70 . 
     The mast  22  is fitted with a jib crane  73  and hoist  74 . The hoist  74  has a travelling block  75 . Bales and an elevator  76  are hung from the block  75  for lifting lengths of casing, tubing and the like. 
     Rather than use a separate crane to lift and lower long lengths of sectional tubing (e.g. 30 feet long) at the well, the jib crane  73  extension is provided from the mast  22 . Further, to enable alignment of sectional tubing  15  over the BOP  51 , the coiled tubing rig injector  20  must be moved out of its working alignment from the BOP  51 . Accordingly, the mast  22  is pivotable adjacent the BOP  51  so as to tilt it out of the way and permit the jib crane  73  access to the BOP. 
     Once a Bottom Hole Assembly (BHA) or other sectional tubular components  15  are placed at or through the BOP, there must be means capable of making up the threaded joints. 
     Having reference to FIGS. 4-7 b , mounted atop the BOP  51  is a rotary table  100  which comprises top and bottom housings  101 , 103 , spaced apart by a ring bearing  102 . As shown in FIG. 4, the bottom housing  103  is incorporated into a flow tee  104 . Generally, the flow tee  104  is positioned directly above the BOP  51 . The top and bottom housings  101 , 103  have a bore  105  which is complementary to the BOP  51  and wellhead, suitable for passing the coiled tubing  14  and also jointed sections such as the BHA. 
     The bottom housing  103  comprises an upstanding sleeve  106  having an intermediately located and radially outward projecting annular bottom shoulder  107 . The top housing  101  has a downward extending sleeve  108  and an intermediately located inwardly projecting annular top shoulder  109 . The upstanding sleeve  106  of the bottom housing  103  fits closely through the top shoulder  109 . The downward sleeve  108  of the top housing  101  fits closely over the bottom shoulder  107 . O-Ring seals  110  at the nose of each of the top and bottom shoulders  109 , 107  seal against the bottom and top housings sleeves  106 , 108  respectively. 
     The ring bearing  102  is sandwiched between the top and bottom annular shoulders  109 , 107 , permitting the top housing  101  to rotate freely on the bottom housing  103 . 
     The top housing  101  is retained to the bottom housing  103  using a threaded collar  111  located below the bottom shoulder  107 . The collar  111  is threaded onto the top housing&#39;s sleeve  108 , pulling the top housing  101  onto the bottom housing  103 , loading the ring bearing  102  therebetween. 
     Best shown in FIG. 6 a , the ring bearing  102  is sectional comprising a top race  112 , a bottom race  114  and an intermediate cage ring  113  fitted with a multiplicity of ball bearings  115 . In FIG. 4, one can see that, when assembled, the bottom race  114  is seen to be supported by and rests on the bottom shoulder  107 . The cage ring  113  rests on the bottom race  114  and the top race  112  bears against the cage ring  113 . 
     In FIG. 5, the top housing  101  seen to provide a general service rotary section  120  supported on the ring bearing  102  rotation about the vertical axis  20  of the BOP  51 . 
     The rotary section  120  further incorporates means  121  for controllably and periodically gripping the jointed sections  15  while operations are performed. Gripping means  121  are installed to grip the jointed section  15  and form a bottom surface  122  for transmitting the weight of the gripped jointed sections through the top housing  101  and into the annular bearing  102 . Thus, the jointed sections  15  are prevented from being lost down the well yet, are easily rotated on the annular bearing  102  for making up successive threaded joints of tubing  15 . 
     The gripping means  121  are typically a slip arrangement or a split clamp. After the gripping means  121  are secured about the jointed section  15 , it bottom surface  122  is lowered into engagement with the top housing  101  or rotary section  120  and the top housing bears against the top race and transmits the weight of the jointed section  15  into the BOP  51  while permitting it to rotate. Typically, it is inconvenient to access the end of the jointed section  15  to apply the gripping means  121 . Accordingly, the gripping means  121  can be applied to support at the mid-point of a length of tubing. 
     One conventional form of gripping means (not shown) include a plurality slip type gripping units (not shown). Circularly spaced wedge slips have outer tapering surfaces which engage correspondingly tapered surfaces of the rotary section to cam the slips inwardly in response to downward movement thereof. The inner gripping faces of the slips are formed with teeth or other irregularities adapted to engage the outer surface of the jointed section to transmit tubing weight into the rotary section and support it in the well. 
     Another form of rotary section gripping means  121  is a split clamp (FIG. 5) having a cylindrical body split diametrically into two body halves  123 . Two body halves  123  have facing semicircular recesses or gripping surfaces  124  and are positioning on either side of the tubing  15  to be supported. The two body halves  123  are sized so that when clamped about tubing  15 , they do not bottom against each other, the diametral depth of their combined recesses  124  being less than the diameter of the jointed section  15 . 
     When clamped about the tubing  15 , the two body halves  124  combine to become the cylindrical body of the split clamp gripping means  121  which then rests upon the top housing  101 . 
     A BHA can now be made up by supporting each jointed section  15  through the BOP  51 , supported by the split clamp body halves  123 , 123  and top housing  101  and be rotated while using chain tongs to tighten joints. Further, the completed and heavy BHA can be rotated freely and supported on rotary section  120  so as to thread it onto the connection to the non-rotating coiled tubing  14 . As shown in FIGS. 5 and 6 c , once the tubing  15  is through the top housing, an inflatable packer  116  is inflated to seal the tubing  15  therein. 
     By implementing the rotary table  100  as described, it has been found that usual BHA make up time of about 6 hours can now be accomplished in about 0.5-1.0 hours. 
     Further once spudded in and surface casing is placed, the preferred coiled tubing rig can drill 1100 meters of hole and have production casing placed, including cement, in about 16 hours, faster than that of a conventional jointed tubing rig by about 24-30 hours. The surface hole can be drilled using sectional tubing  15  or using the coiled tubing  14 . Surface casing run in with the jib  73  and elevators  76 . 
     The preferred injector  20  is capable of up to 15,000 lb. force and it with PDC bits (polycrystalline diamond compact, typically needing only about 9,000 lbf) may not even be necessary to use additional drill collars for weight. Drill collars may yet be added for stabilization to aid in keeping the surface hole straight.