Abstract:
The present invention provides an apparatus and method for partially rotating a drill string. The drill string of the present invention comprises upper and lower sections wherein the lower section rotates relative to the upper section of the drill string from the surface at the injector head. The upper and lower sections of the drill string can comprise coiled tubing, jointed tubing or a combination of coiled and jointed tubing. The lower section of the drill string comprises a bottom hole assembly (BHA), which comprises a drill bit and downhole drilling motor. A rotational device is positioned within the drill string in order to rotate the lower section. Upon activation of the rotational device, the lower section of the drill string will be exposed to a continuous rotation. By partially rotating the lower section of the drill string, static friction forces are overcome, the probability of differential sticking of the drill string is reduced and the cuttings produced during drilling are prevented from settling on the bottom (low side) of the wellbore, thereby maintaining a clean wellbore by dragging the cuttings back into the main fluid path.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application takes priority from U.S. Patent Application Serial No. 60/153,717, filed Sep. 14, 1999. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates generally to oilfield well operations and more particularly to an apparatus and method for rotating a portion of a drill sting in a subterranean wellbore. 
     2. Background of the Invention 
     In drilling oil and gas wells for the exploration of hydrocarbons, it is sometimes necessary to deviate the well off vertical and in a particular direction. A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal boreholes, to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from the earth&#39;s formations. Modern directional drilling systems generally employ a drill string having a bottom hole assembly (BHA) and a drill bit at the end thereof that is rotated by a drill motor and/or the drill string. 
     In vertical or near vertical drilling, cuttings produced while drilling are efficiently carried away from the wellbore by the upward velocity of the drilling fluid (commonly known as the “mud” or “drilling mud”). However, where there is more deviation in the well, the force of gravity results in the cuttings settling along the bottom side of the wellbore (sometimes referred to as the “low side”). As the cuttings settle, a “bed” of solids can form, which can significantly increase the drag forces on the drill string. 
     Slide-type drill string, or in particular, coiled tubing, involves a pulsating advancement of the drill string in an attempt to constantly overcome the static friction of the drill string on the formation. Drill strings which include jointed pipe as the drill pipe are rotated from the surface to change the static friction to a dynamic friction. 
     Current coiled tubing drilling applications, involving non-rotating drill strings, are limited by the friction created by the formation of solids in the bottom of the wellbore and the string compressible load capability in achieving the necessary depths of extended reach wellbores or highly deviated wellbores. As a result of the non-rotational setup of coiled tubing applications, the drill string is exposed to enormous amounts of axial frictional forces while sliding the drill string into and out of the wellbore. The horizontal inclinations and curvature in the wellbore increase the likelihood that a non-rotating drill string will become lodged or “stuck” in the wellbore, thereby preventing further insertion or extraction of the drill sting. 
     Drill strings may also become lodged in a wellbore as a result of differential sticking. Differential sticking occurs when the drill string remains at rest against the wellbore wall for a sufficient amount of time to allow filter mud to build up around the drill string. The portion of the drill string that is in contact with the mud is sealed from the hydrostatic pressure of the mud column. The pressure difference between the mud column and the formation pressure of the adjoining formation acts on the area of the drill string in contact with the mud to hold the drill string against the wall of the wellbore. This frictional engagement between the drill string and the mud inhibits or prevents axial and rotational movement of the drill string. However, the kinetic force of a rotating drill string can minimize or deter differential sticking. 
     Even when a jointed pipe is used as the drill pipe, rotation of the drill pipe from the surface can damage drill pipe around short radius curves and can also damage the borehole at such locations. Continuously rotating the drill string, especially along horizontal or highly deviated sections of the wellbore, can significantly reduce drag, improve hole cleaning, i.e. move cuttings through the borehole and also facilitate tripping of the drill string from the borehole. 
     U.S. Pat. No. 5,738,178 provides (i) coiled-tubing drill strings wherein the bottom hole assembly can be rotated without rotating the coiled tubing; and (ii) drill pipe drilling systems wherein the drill pipe above the bottom hole assembly can be rotated independent of the bottom hole assembly. However, to drill extended reach horizontal wellbores with coiled tubing drill strings, it is advantageous to rotate at least a portion of the tubing in the horizontal section with and/or without rotating the bottom hole assembly. To drill the wellbore with drill pipe drill strings, it is also advantageous to rotate at least a portion of the drill pipe in the horizontal section without necessarily rotating the remaining drill pipe from the surface. 
     The present invention provides apparatus and method for rotating a portion of the drill string in the wellbore. By rotating a portion of the drill string, the kinetic force prevents cuttings produced during drilling from settling in the wellbore, thereby significantly reducing the static friction between the rotating portion of the drill string and its surrounding elements and reducing the probability of differential sticking and thus allowing drilling of deeper wellbores by such a drill string compared to a non-rotating drill string. Such a system also facilitates tripping of the drill string from the wellbore. 
     SUMMARY OF THE INVENTION 
     The present invention provides apparatus and method for rotating a portion of a drill string in the wellbore. The drill string of the present invention comprises upper and lower sections wherein the lower section rotates relative to the upper section of the drill string which extends to the surface. The upper and lower sections of the drill string can comprise coiled tubing, jointed tubing or a combination of coiled and jointed tubing. The lower section of the drill string comprises at least a portion of a bottom hole assembly (BHA), which includes a drill bit and downhole drilling motor. A rotational device is positioned within the drill string in order to rotate the lower section. Upon activation of the rotational device, the lower section of the drill string will be exposed to a continuous rotation. By rotating the lower section of the drill string in the wellbore, static friction forces exhibited by the lower portion are overcome. This reduces the probability of differential sticking of the drill string in the wellbore and can prevent settling of the cuttings on the bottom (low side) of the wellbore, which allows the cuttings to move more freely with the drilling fluid. 
     An alternative embodiment of the present invention comprises at least one rotational device positioned between the upper and lower sections of the drill string wherein the rotational device allows for passage of wireline and/or fluid. 
     Another embodiment of the present invention includes at least two spaced apart rotational devices, each such device adapted to independently move a portion of the drill string downhole of the rotational device. 
     Examples of the more important features of the invention thus have been summarized rather broadly in order that detailed description thereof that follows may better be understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For detailed understanding of the present invention, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein: 
     FIG. 1 illustrates a schematic diagram of a partially rotatable drilling string according to the preferred embodiment; 
     FIG. 2 illustrates a detailed diagram of the partially rotatable drilling string according to the preferred embodiment; 
     FIG. 2A illustrates drilling of a wellbore along an exemplary trajectory with a drill string made according to one embodiment of the present invention; 
     FIG. 3 illustrates a cross-sectional view of a portion of the lower section of the drill string; 
     FIG. 4 illustrates a cross-sectional view of a portion of the lower section of the drill string and the fluid path from the surface workstation to the bottom hole assembly; 
     FIG. 5 illustrates a cross-sectional view of a portion of the lower section of the drill string and an alternative fluid path from the surface workstation to the bottom hole assembly; and 
     FIG. 6 illustrates a cross-sectional view of a portion of the lower section of the drill string which allows passage of wireline and fluid. 
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The present invention provides an apparatus and method for rotating a portion of a drill string in any deviation from vertical to horizontal. During drilling of deviated and horizontal wellbores, drill cuttings tend to gravitationally settle and form solids on the bottom (low side) of the wellbore. Drag due to static friction in non-rotating drill strings can be several times greater than the drag when at least a portion of the drill string is continuously rotated. This is particularly problematic when drilling is performed with coiled tubing. Drill strings utilizing drill pipe (jointed tubulars) can be rotated from the surface but require great energy and may not be suitable for short radius and/or extended reach horizontal wellbores. 
     FIG. 1 illustrates an exemplary drilling system  100  wherein a supply of ductile tubing  120 , capable of being spooled upon a tubing reel  10 , is positioned on a surface workstation  130  (such as a rig or an offshore vessel or an offshore platform) for insertion into or extraction from a wellbore  140 . An injector head unit  20 , also located on the surface workstation  130 , is utilized for inserting and retrieving the tubing  120  relative to the wellbore  140 . It is contemplated that relatively rigid jointed pipe or tubing may also be used in the present invention. In such drill strings, the drill pipe is inserted or retrieved by apparatus well known in the art and the drill string can be rotated by a rotary table at the workstation  130 . 
     In the present invention, a drill string  30  extends from a location on the surface workstation  130  to a certain depth “D” in the wellbore  140 . The drill string  30  contains a bottom hole assembly (BHA)  80  located at the lowermost end of the drill string. The bottom hole assembly  80  includes a drill bit  110  for drilling the wellbore  140  and a drilling motor  90 . A drilling fluid  65  from a surface mud system (not shown) is pumped under pressure down the drill string  30 . The drilling fluid  65  operates the drilling motor  90  within the bottom hole assembly  80 , which in turn rotates the drill bit  110 . The drill bit  110  disintegrates the formation (rock) into cuttings. The drilling fluid  65  along with the cuttings leaving the drill bit  110  travels uphole in the annulus between the drill string  30  and the wellbore  140 . However, in deviated and horizontal wellbores cuttings tend to settle along the bottom of the wellbore  140 , which can cause the drill string  30  to become lodged. This is especially prevalent when the drill string in the horizontal section is not rotating due to the static friction between the drill string and the wellbore. The force of the drilling fluid alone may not be sufficient to move the drill cuttings through the low side of the annulus. Therefore, it is desirable to create a kinetic force at least within the deviated sections of the wellbore  140  in order to prevent the cuttings from settling or to reintroduce the cuttings into the main fluid path. 
     Referring to FIG. 2, a kinetic force is generated downhole with the use of a rotational device  50 , preferably a motor, which is placed along the drill string  30 , a selected distance above the bottom hole assembly  80 . The rotational device  50 , comprising an engagement device  55  and a power unit  57  coupled to the engagement device  55 , provides rotary motion to the drill string  30 . The rotational device may be operated from a remote location. The power unit  57  may comprise an electric motor, pneumatic motor, a mud motor or turbine driven by the fluid supplied to the drill string  30  during drilling. 
     The drill string  30  comprises a plurality of sections defined by placement of at least one rotational device  50  on the drill string  30 . The upper section  40  comprises the section of the drill string  30  above or uphole of the rotational device  50  and the lower section  70  comprises the section of the drill string  30  below or downhole of the rotational device  50 . The lower section  70  may include the bottom hole assembly  80  and a certain length  10   a  of the tubing  10 . The length of the section  10   a  is selected depending upon the intended horizontal reach of the wellbore. This section may be from a few hundred feet to more than a thousand feet in length. The length of the section  10   a  is selected so that it&#39;s rotation is sufficient to reduce the static friction to allow proper hole cleaning and insertion of the drill string  30  into the wellbore  140  during drilling. The section  10   a  is preferably relatively rigid and may be a jointed pipe. 
     The upper section  40  may be a coiled tubing on a rigid tubing. When a coiled tubing is used as the upper section  40 , it is fixedly attached to the upper end of the rotational device  50 . When a rigid pipe is used, it may be fixedly attached via a selective engagement device  51   a  so that in one mode the upper section  40  and the lower section  70  can be engaged with each other to rotate together and in a second mode they can be rotationally disengaged so that the lower section  70  may be rotated independent of the upper section  40 . Any suitable device may be used as the engagement device  51   a  for the purpose of this invention. For example, the present invention may utilize any swivel and clutch type mechanism or it may utilize an adaptation of the engagement device shown in U.S. Pat. No. 5,738,178, the entire disclosure of which patent is incorporated herein by reference. 
     In an alternative embodiment, a rotational device  60  may rotate the bottom hole assembly at joint  77  between the tubing and the bottom hole assembly  80 . The rotational device  60  may rotate the lower string segment  70  relative to the upper string segment  40  at a relatively slow rate of speed to facilitate advancement of the drill string into the wellbore The bottom hole assembly  80  can be in excess of 100 feet and is usually significantly larger (in outer dimensions) than the tubing  10  and thus can be a source of inducing a substantial amount of the static friction. Rotating the bottom hole assembly in certain applications may be sufficient to drill extended reach wellbores. 
     Alternatively, more than one independently operable rotational devices may be utilized in the drill string  30 . For example, one rotational device  60  to rotate the bottom hole assembly  80  and the second rotational device  50  to rotate section  10   a  of the tubing  10 . The rotational devices may rotate the section  10   a  only or section  10   a  along with the bottom hole assembly  80 . The rotational devices  50  and  60  are preferably independently operable by a control circuit  65  in the bottom hole assembly  80  and/or by a control circuit or unit  45  (FIG. 1) at the surface. If the upper section  40  is made from a rigid tubing, the entire drill string may be rotated to drill a portion of the wellbore. 
     Drilling of an extended reach horizontal wellbore, according to one method of the present invention, is described in reference to FIG. 2 a  below, which illustrates an exemplary wellbore  120  having a particular profile or trajectory that includes an initial vertical section  120   a  extending from a surface location  115  to a first depth d 1  followed by a relatively short radius section  120   b  having a curvature defined by radius “R” to a second depth d 2 , which is followed by a straight inclined or horizontal section  120   c  to a depth d 3 . 
     The wellbore  120  is shown being drilled by a particular embodiment of a drill string  30  made according to one embodiment of the present invention. For convenience, the elements of the drill string  30  of FIG. 2 a  that are common with the drill string of FIG. 2 are denoted by common numerals. The drill string  30  includes a rotational device  50   a  between an upper section  10   b,  which preferably is a coiled tubing, and a lower rigid pipe section  10   b.  A bottom hole assembly  80  is attached to the lower end of the bottom section  10   b  via a rotational device  60 . The bottom hole assembly preferably includes a mud motor  90  for rotating the drill bit  110 . Independently operable force application members  95   b  apply force on the wellbore wall to maintain the desired drilling direction. The bottom hole assembly  90  may include other directional drilling devices which aid the drill string  30  in drilling deviated holes and maintain the drill bit along a particular direction. 
     To drill the initial vertical section  120   a,  the drill string lower section  10   a  may be rotated. When a coiled tubing is used as the upper section it remains non-rotating. If a rigid drill pipe is used as the upper section  10   b,  both the upper and lower sections may be rotated to drill the section  120   a.  If the radius R is too short, such section may be drilled by only rotating the bottom hole assembly  80  by the rotational device  50   b  or by not rotating any portion of the drill string  30 , except the drill bit  110  by the drilling motor  90 . 
     The initial portion of the horizontal or inclined section  120   c  is drilled to a depth as the curved hole so that the lower section  10   a  lies in the horizontal section  120   c.  Further drilling preferably is performed by rotating the drill bit  110  by the mud motor  90  and by continuously rotating at least the lower section  10   a  of the drill string by the rotational device  50   a.  The bottom hole assembly  90  may also be rotated, if desired, by the rotational device  60 . As noted above, the drill string of  30  allows independent selective rotation (i) of the bottom hole assembly below the device  60 , (ii) of the lower drill string section  10   a  below the rotational device  50   a;  and (iii) of the upper section  10   b  from the surface, if a rigid tubing is used as the upper section. Additional rotational devices such as  50   b  may be incorporated at suitable locations in the drill string  30 . The device  60  may also be utilized for directional control of the drill bit, as described in U.S. Pat. No. 5,738,170. 
     Thus, the present invention allows drilling of a wellbore wherein at least a portion of the drill string above the bottom hole assembly can be continuously rotated. The rotational speed can be controlled from the surface control unit  45  or by utilizing a telemetry system in conjunction with the power unit  57  (FIG.  2 ). The continuous rotation of the drill section  10   a  maintains dynamic friction of such section, thereby reducing drag, which allows easy insertion of the drill string  30  into the wellbore  140  for continued drilling. This also facilitates the movement of the drill cuttings  121  through the annulus  122 . To retrieve the drill string from the wellbore  140 , the lower section  10   a  can be continuously rotated while the injector head  20  or another suitable system pulls out the drill string  30  out from the wellbore. 
     Drill bit sometimes can get lodged or stuck into wellbore bottom. In such situations, rotating the drill string section  10   a  can facilitate the removal of the drill bit  110 . In cases when a stuck drill bit cannot easily be dislodged, the drill string of the present invention provides a breakaway device  150  at a suitable location in the drill string  30 . The drill string  30  can be disconnected at such device  150 , which allows the removal of the drill string above the device  150  from the wellbore. Such removal is relatively easy since at least a portion of the drill string remains in continuous rotation. The device  150  can be installed in the bottom hole assembly  80  above the drill bit  110 . In this manner at least a portion of the bottom hole assembly can be recovered, which is usually the most expensive part of the drill string  30 . 
     The above-described staged drilling, i.e. drilling different sections in different modes, can provide more effective and efficient drilling compared to drill strings which do not allow rotation of at least a portion of the drill string above the bottom hole assembly. The location of the rotatable devices  50   a  and  50   b  can be changed whenever the drill string is tripped out of the wellbore, which occurs several times during drilling of extended reach wellbores. 
     FIG. 3 illustrates a cross-sectional view of a portion of the lower section  70  of the drill string  30  which comprises an inner drive train  260 . The inner drive train  260  comprising a drive sub  200 , a flex shaft  220  and the power unit  57 , is connected to the upper section  40  of the drill string  30  (FIG.  1 ). Adjacent the inner drive train  260  is the outer housing  210 , which rotates in response to the fluid flow through the power unit  57  when the power unit comprises either a mud motor or turbine. 
     FIG. 4 illustrates the fluid path which originates from the surface into the drive sub  200 , through the flow ports  200  and through the chamber of the power unit  57 , which comprises a stator housing  230  and a rotor  240 . Utilization of this fluid path allows for rotation of the outer housing  210  of the lower section  70  of the drill string  30 . The fluid path continues through the lower section  70  of the drill string  30  to the bottom hole assembly  80 . 
     FIG. 5 illustrates an alternative fluid path. This fluid path occurs when the flow ports  200  are closed, thereby allowing fluid to flow directly to the bottom hole assembly  80  without passing though the chamber of the power unit  57 . Therefore, when the fluid ports  200  are closed, there is no rotation of the lower section of the drill string. 
     FIG. 6 illustrates a path within the lower section of the drill string wherein at least one rotational device along the drill string allows passage of wireline and fluid while providing rotary motion to the drill string. 
     The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the spirit of the invention.