Abstract:
A method and apparatus for removing tubulars from a wellbore is disclosed. A lifting member grips the tubular and applies a lifting force. The lifting force is then transferred to a first surface. The lifting member is monitored and when the capacity of the first surface is reached a force transfer assembly is activated. The force transfer assembly transfers the lifting load between the first surface and a second surface. The lifting member and force transfer assembly are then adjusted to maximize the amount of lifting force applied to the tubular.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001]     This application claims benefit of U.S. provisional patent application Ser. No. 60/726,946, filed Oct. 14, 2006, which is here incorporated by reference. 
     
    
     BACKGROUND OF THE INVENTION  
       [0002]     1. Field of the Invention  
         [0003]     Embodiments of the present invention generally relate to a method and apparatus for removing tubulars from a wellbore. Particularly, the present invention relates to a method and apparatus for increasing the amount of lifting force applied to a wellbore tubular when removing the tubular from the ground. More particularly still, the present invention relates to a method and apparatus for distributing the lifting force between two separate load surfaces for an increased lifting force. More particularly still, the present invention relates to controlling and monitoring a lifting force between two separate load surfaces.  
         [0004]     2. Description of the Related Art  
         [0005]     In the operation of oil and gas wells, it is common to remove well tubulars from the wellbore. Often such tubulars are stuck in the wellbore and therefore removal from the wellbore is difficult. The types of tubulars removed are casing, drill pipe, liner, production tubing, coiled tubing, or any other type of tubular used in a wellbore. Tubulars are removed from the wellbore for a number of reasons, such as remediation or to pull out and abandon the well. Currently, tubular removal uses an elevator of a drilling rig, or a hydraulic jack placed on the rig floor, or on the wellhead surface. These systems connect to the tubular and attempt to lift the tubular and break it free from the stuck point. The tubular is then lifted out of the wellbore.  
         [0006]     The use of an elevator to pull wellbore tubulars may be dangerous and limited under heavy load situations. The elevator pulls at the tubular with a cable and pulley system. If the gripping apparatus or cables fail while pulling, a sling shot effect is created. The movement of the gripping apparatus or cables after failure creates a great risk to workers and equipment on the drilling rig.  
         [0007]     In order to minimize hazards presented by elevators, it is known to use hydraulic jacks to pull wellbore tubulars. The hydraulic jack systems rest either on the rig floor or on the surface of the wellbore. However, when lifting tubulars from the wellbore either on the rig floor or wellbore surface alone are often insufficient for supporting the load required to break the tubular out of the ground. To solve this problem in the past additional structural members have been welded to the drill rig floor in order to increase the loading capacity of the rig. Further, if the hydraulic jack is placed on the wellhead, the jack often extends above the rig floor. Therefore, the rig floor has to be modified to allow the jack to pass through the floor. These approach is costly and time consuming.  
         [0008]     Further, existing hydraulic jacking systems include a plate attached to the jack which has a closed circular aperture which surrounds the tubular during removal. However, if the tubular to be gripped continues above the rig floor, such as the case with coiled tubing, it is necessary to first cut the tubular before the jack is placed over the tubular.  
         [0009]     Therefore, there is a need for an apparatus and method of removing tubulars from a wellbore that increases the load capacity of the lifting system without the need to modify a structure. There is a further need to lift tubulars from a wellbore without the need to cut the tubular during the jacking process.  
       SUMMARY OF THE INVENTION  
       [0010]     Embodiments described herein generally relate to a wellbore tubular removal system having a gripping member for gripping a tubular in a wellbore, a lifting member engagable with the gripping member for lifting the tubular, a force transfer member to transfer a lifting force from the lifting member to a surface and a force transfer assembly to distribute a lifting force between the surface and a second surface.  
         [0011]     Embodiments relate to a wellbore tubular removal system having a gripping member for gripping a tubular in a wellbore, and a lifting member engagable with the gripping member for lifting the tubular, a force transfer assembly to transfer a lifting force from the lifting member to a first surface, a force distribution assembly to divide a lifting force between the surface, and a second surface. The lifting member is a jack, which in one embodiment includes one or more fluid operated pistons. The jack has a monitoring device for monitoring the lifting force in the lifting member. The monitoring device restricts the lifting force to the maximum force the first surface and the second may carry. The force distribution assembly is a second jack. The first surface may be a structure of the wellbore. For example, the first surface may be a blowout preventor, casing stub, or a well head of the wellbore. The second surface may be a portion of a rig floor or a rotary table. The force transfer assembly comprises a spacer spool, which rests on top of the first surface. The top of the spacer spool is engagable to the second jack. The second jack has a monitoring device for monitoring the lifting force in the second jack.  
         [0012]     Embodiments described herein relate to a wellbore tubular removal apparatus having a tubular gripping member engaged to a first jack, a second jack configured to rest between a top of a structure and the first jack, and a force transferring assembly. The force transferring assembly engagable to the second jack and a surface of the wellbore, wherein a lifting force created by the first jack is transferred through the force transferring member to the surface. In one embodiment, the first jack comprises one or more fluid operated cylinders. The tubular removal apparatus includes a plate having an aperture through which the tubular may pass. The second jack includes an aperture which may have a semicircular configuration and one or more jacks. The second jack further includes an aperture through which the tubular may pass. The lifting force is distributed, shared and controlled between the structure and the surface upon actuation of the second jack.  
         [0013]     Embodiment described herein relate to a method for removing a tubular in a wellbore by gripping the tubular, lifting the tubular with a lifting member, transferring a lifting force from the lifting member to a first surface via a force transferring member, and using a force transferring assembly to distribute, control and share the lifting force from the lifting member between a second surface and the first surface. The invention monitors the lifting force in the lifting member and the force transfer assembly and controls the amount of lifting force applied to the first surface and the second surface. The first surface and the second surface may be in separate horizontal planes and the tubular may be uncut coiled tubing.  
         [0014]     Further, embodiments described herein relate to an apparatus for removing a tubular from a wellbore having a gripping member for gripping a tubular in the wellbore and a lifting member engagable with the gripping member for lifting the tubular. The lifting member comprises a jack. The jack having one or more fluid operated cylinders attachable to a plate, which may be a semicircular plate, at the top of the fluid operated cylinders. The jack having a second plate, which may be a semicircular plate, attachable to the bottom of the fluid operated cylinders. The lifting member is designed to straddle a tubular. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0015]     So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.  
         [0016]      FIG. 1  is a cross sectional elevation view of a tubular attached to the lifting system according to one embodiment.  
         [0017]      FIG. 2  is an isometric view of a jack with the semi-circular plate configuration according to one embodiment. 
     
    
     DETAILED DESCRIPTION  
       [0018]      FIG. 1  illustrates a cross sectional elevation view of a tubular  100  attached to a lifting apparatus  1 . The tubular  100  is any tubular for use in downhole wellbores such as, but not limited to, casing, liner, drill string, coiled tubing, and production piping. The lifting apparatus  1  includes a gripping member  10  for gripping the tubular  100 . As shown, the gripping member  10  is a spider type gripper such as that disclosed in U.S. Publication No. 2004/0251055 A1, which is herein incorporated by reference; however, it should be appreciated that the gripping member  10  may be any type known in the art such as a spear, as disclosed in U.S. Publication No. 2005/0051343 A1, which is herein incorporated by reference, or any other device adapted to grip tubulars. The gripping member  10  attaches to a lifting member  20 .  
         [0019]     The lifting member  20 , as shown, comprises a hydraulic jacking system with one or more fluid operated cylinders  21  attached to a top plate  23  and a bottom plate  25 . The top and bottom plates  23  and  25  have an opening  27  through which the tubular  100  fits. The opening  27  forms a hole through which the tubular  100  is run through or it may have a semicircular formation as shown in  FIG. 2 . The semicircular or open design allows the jack to straddle the tubular  100  without the need to cut the tubular  100  if the tubular  100  is continuous or is raised high above a rig floor  50 . The top and bottom plates  23  and  25  have any configuration or support scheme necessary to support the load of the lifting member  20  and allows for the tubular  100  to pass through the plates  23  and  25 . Further, the lifting member  20  may comprise any type of lifting or jacking device such as a mechanical jack.  
         [0020]     The advantage of the semicircular or c-plate configuration of plates  23  and  25 , as shown in  FIG. 2 , is that it allows the jack to straddle any tubular  100 . Often in the removal of tubulars  100  from a wellbore, the tubular extends high above the rig floor  50 , or is a continuous string of tubing. Cutting the tubular  100  in order to place a jack over it is time consuming and costly. Cutting the tubular  100  often damages the integrity of the tubular  100 . Thus the semicircular plates allow an operator to quickly move the lifting apparatus  1  into place and begin lifting the tubular  100 . Further, only the lifting member  20  may be used for quick removal of the tubular  100 .  
         [0021]     The lifting member  20  transfers a lifting force to a surface  200  via a force transfer assembly  30 . As shown, the force transfer assembly  30  is a spool piece adapted to fit around the tubular  100 . The spool piece may have a circular opening through its center or be adapted, like the top and bottom plates  23  and  25 , with one side open to slide around the tubular  100 . The force transfer assembly  30  may also be a spilt spool piece. The split spool piece is two or more longitudinally cut spool sections which fit around the tubular and are then connected to form one unit. The spool piece may have a diameter only slightly larger than the diameter of the tubular  100 . This allows the spool piece to be used without modifying the rig floor. Further, the force transfer assembly  30  may be any structure for transferring the lifting load to the surface  200 , such as columns, one or more pipes, or structural members. The force transfer assembly  30 , as shown, rests on top of the surface  200  at the bottom and at the top carries the lifting force from the lifting member  20 .  
         [0022]     A force distribution assembly  40  transfers the lifting force from the gripping member  10  to a second surface  50 . The location of the second surface  50  is unimportant as long as the lifting force is distributed to somewhere other than the first surface  200 . The force distribution assembly  40 , as shown, comprises a jack which includes one or more fluid operated cylinders  41 . The force distribution assembly  40  further includes a top plate  43  and a bottom plate  45 . The top and bottom plates  43  and  45  are of the same type as described above for plates  23  and  25 , and thus will not be described again. The force distribution assembly  40 , though shown as a fluid operated jack, may be any type of lifting device such as a hydraulic, pneumatic, or mechanical jack.  
         [0023]     The force distribution assembly  40 , as shown, holds the lifting member  20  on its top plate  43 . The bottom of the top plate  43  rests on the force transfer assembly  30  via a spacer plate  49 . The spacer plate  49  provides for even load distribution and to shim small differences in space; however, it is not necessary for the invention. The lifting member  20  and the force distribution assembly  40  each connect to a sensor  500  and  502 , respectively. The sensors  500  and  502  send data to an operator or a controller  900 . The controller  900  or operator are located at any location, and if necessary far from the wellbore. The controller  900  or operator monitors and adjusts the pressure in the cylinders  21  and  41  as needed. The sensors  500  and  502  are of any type that will read the load in the lifting member  20  and force distribution assembly  40 , such as a hydraulic pressure gauge, pressure sensor, a strain gage, or a scale.  
         [0024]     The pressure sensors  500  and  502  and the controller  900  or operator ensure that the first surface  200  and second surface  50  are not overloaded. For example, the first surface  200  has maximum load of Y and the second surface  50  has a maximum load of X. The maximum loads are determined by finding the maximum load the surfaces can hold and multiplying that number by an acceptable safety factor. The controller  900 , or operator, is set so that when the second sensor  502  reaches X, the loading of the force distribution assembly  40  is stopped. The lifting force or load in the force distribution assembly  40  is X′. The maximum loading of the lifting member  20  is Y plus the X′. Thus, with no lifting force in the force distribution assembly  40 , the lifting member lifts a lifting force equal to the maximum load Y of the first surface  200 . Once the force distribution assembly  40  is actuated, the lifting force in the lifting member  20  may increase by the equivalent amount of lifting force in the force distribution assembly  40 , X′. Therefore, both the first surface  200  and the second surface  50  may carry their maximum loading. The amount of lifting force applied to the tubular  100  is increased by the maximum load capacity of each surface  50  and  200 . The total maximum load of the apparatus  1  may further be determined by the maximum yield strength of the tubular  100 , or the tubular couplings (not shown).  
         [0025]     The controller  900  is capable of receiving data from the sensors  500  and  502  and other devices and is capable of controlling devices connected to it. One of the functions of the controller  900  is to prevent overloading of the surface  200  and the second surface  50 . The controller  900  reads the sensors  500  and  502  and adjusts the pressure in the lifting member  20  and force distribution assembly  40  in order to prevent an overload of either of the surfaces  50  and  200 . Further, the controller  900  may be equipped with a programmable central processing unit that is operable with a memory, a mass storage device, an input control unit, and an optional display unit. Additionally, the controller  900  includes well-known support circuits such as power supplies, clocks, cache, input/output circuits, and the like.  
         [0026]     Further, the controller  900  may include or simply be one or more pumps for controlling the hydraulic pressure in the lifting member  20  and the force distribution assembly  40 . The hydraulic lines running from the one or more pumps include one or more pressure relief valves  901  in order to control the amount of pressure in the hydraulic cylinders  21  and  41 . The pressure relief valves  901  are adjustable. Thus, an operator or the controller  900  may adjust the one or more pressure relief valves  901  for the maximum load capacity of the first and second surfaces  50  and  200 . In the alternative, an operator reads the sensors  500  and  502  and bleeds pressure from the hydraulic cylinders  21  and  41  according to the maximum load capacity of the first and second surfaces. In another alternative, the sensors  500  and  502  are pressure relief valves and they are merely preset to properly distribute the jack load wherein no direct interaction between the controller  900  or pump and the pressure relief valve is required.  
         [0027]     In operation, the gripping apparatus  10  grips the tubular  100 . The controller  900  or an operator actuates the lifting member  20  so that the hydraulic cylinders apply a lifting force on the tubular  100 . At this time, the force distribution assembly  40  is inactive, thus, the full load from the lifting member  20  transfers to the surface  200  via load transfer assembly  30 . As shown, the surface  200  is the wellbore surface which may comprise a blow out preventor, or a casing bowl, wellhead, or the ground, etc. The controller  900  is set to activate the force distribution assembly  40  when a first predetermined load of the surface  200  is reached. The force distribution assembly  40  then applies force to the bottom of the lifting member  20  which transfers some of the lifting load in the force transfer assembly  30  to the second surface  50 . The second surface  50 , as shown, is the rig floor; however, it may be a rotary table, the derrick, a platform on the derrick, a truck bed, etc. The controller  900  or operator then adjusts the load in the lifting member  20  and the force distribution assembly  40  until a second predetermined load of the surface  200  and the second surface  50  are reached. The predetermined loads may be the maximum load of the surfaces  50  and  200  or any other load desired by the operator, so long as each of the surfaces  50  and  200  are not overloaded. Further, as discussed above pressure relief valves  901  may be used to ensure that the predetermined loads of the surfaces  50  and  200  are not exceeded. This system allows an increased lifting force to be applied of a downhole tubular  100  without the need to modify the existing structure of the rig.  
         [0028]     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.