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.
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 (xe2x80x9cBHAxe2x80x9d) 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""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.
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 xc2xd 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.
USPTO Backgrounds
USPTO Backgrounds