Abstract:
An apparatus for use with a subsea well includes a lubricator configured to attach to subsea wellhead equipment, an electrically-activated tool, and a coiled tubing attached to the electrically-activated tool. The electrically-activated tool is initially provided in the lubricator to allow for deployment of the electrically-activated tool on the coiled tubing into the subsea well. Multiple tools may be deployed independently from within the lubricator to latch into a concentric electrical connector within the well which may also act as a switch. A concentric electrical connector will permit the passage of a tool through the body of the connector retaining full bore access when the tool is withdrawn.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present document is based on and claims priority to U.S. Provisional Application Ser. No. 61/260/281, filed Nov. 11, 2009. 
     
    
     BACKGROUND 
       [0002]    To produce fluids (such as hydrocarbons) through a well, various equipment are deployed into the well. Examples of such equipment include completion equipment such as casing, production tubing, and other equipment. Once installed in the well, the equipment allows for production of fluids from a reservoir surrounding the well to the surface. 
         [0003]    Certain wells have insufficient reservoir pressure to propel fluids to the surface. A reservoir with a relatively low pressure may not be able to produce sufficient fluid flow to overcome various opposing forces, including forces applied by the back pressure of a column of water, frictional forces of conduits, and other forces. To produce fluids from reservoirs having limited reservoir pressures, artificial lift equipment can be deployed. Examples of artificial lift equipment include pumps such as electrical submersible pumps (ESPs) or other types of pumps. 
         [0004]    Installing an ESP or other type of intervention equipment into a well can be time consuming and expensive. This is particularly the case with subsea wells, since well operators would have to transport the intervention equipment by marine vessels to the subsea well sites. Subsea well operators are often reluctant to perform ESP installation in subsea wells due to the cost of installation, and also due to the possibility that failed ESP equipment may have to be retrieved and replaced with replacement ESP equipment. 
       SUMMARY 
       [0005]    In general, according to some embodiments, a method or apparatus is provided to allow for a more efficient way of deploying an electrically-activated tool (such as an electrical submersible pump) into a subsea well. In one embodiment, an assembly for use in the subsea well includes a lubricator (configured to attach to subsea wellhead equipment), an electrically-activated tool, and a coiled tubing attached to the electrically-activated tool. The electrically-activated tool is initially provided in the lubricator. The electrically-activated tool is then lowered on the coiled tubing from the lubricator into the subsea well. 
         [0006]    Other or alternative features will become apparent from the following description, from the drawings, and from the claims. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0007]      FIG. 1  is a schematic diagram of a marine arrangement for deploying an electrical submersible pump (ESP) into a subsea well, according to an embodiment; 
           [0008]      FIG. 2  illustrates an assembly that includes a lubricator, an ESP, a compliant guide, and a coiled tubing, according to an embodiment; 
           [0009]      FIG. 3  is a schematic diagram of a portion of a production tubing and an ESP, according to an embodiment; and 
           [0010]      FIGS. 4 and 5  illustrate components in a switch sub of the ESP, in accordance with an embodiment; and 
           [0011]      FIGS. 6-8  schematically illustrate components of an ESP according to an embodiment. 
       
    
    
     DETAILED DESCRIPTION 
       [0012]    In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments are possible. 
         [0013]    As used here, the terms “above” and “below”; “up” and “down”; “upper” and “lower”; “upwardly” and “downwardly”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or diagonal relationship as appropriate. 
         [0014]    In accordance with some embodiments, an efficient technique of deploying an electrically-activated tool in a subsea well involves use of a lubricator that has an inner chamber to initially contain the electrically-activated tool. The lubricator is configured to be attached to subsea wellhead equipment. As used here, the term “subsea well” refers to any well that is located under a surface in a marine environment. The electrically-activated tool is deployed into the subsea well by use of coiled tubing. In some embodiments, the coiled tubing is provided without an electrical cable, such that the coiled tubing is used merely as a deployment structure, which reduces the complexity and cost of the coiled tubing. 
         [0015]    To provide electrical power to the electrically-activated tool when the coiled tubing does not include an electrical cable, an electrical connection mechanism is provided on the tool that is used to mate with a corresponding electrical connection sub located on equipment installed in the subsea well. In some embodiments, the electrical connection mechanism on the tool is a wet-mate electrical connection mechanism to allow electrical contact to be made in the subsea well in the presence of fluids. 
         [0016]      FIG. 1  illustrates an example of a marine arrangement that has a subsea well  100  extending below a sea bottom surface  102 . The subsea well  100  is lined with casing  104 . In addition, a production tubing  106  is installed in the subsea well  100 . Fluids from a reservoir surrounding the subsea well  100  flow into the subsea well  100  and up the production tubing  106  to the surface. Although reference is made to production of fluids, it is noted that in alternative implementations, equipment can be provided for injection of fluids through the subsea well  100  into the surrounding reservoir. 
         [0017]    In the example shown in  FIG. 1 , a safety valve  108  is deployed at the lower end of the production tubing  106 . The safety valve  108  is used to shut in the well in case of equipment failure. Although a specific embodiment is shown in  FIG. 1 , it is noted that in alternative embodiments, other or additional components can be provided in the subsea well  100 . 
         [0018]    At the sea bottom surface  102 , wellhead equipment  110  is provided. The wellhead equipment  110  includes a blow-out preventer (BOP)  112  that is used to seal off the subsea well  100  at the surface  102 . 
         [0019]    A high-voltage connector  114  is provided on the wellhead equipment  110 . The high voltage connector  114  is connected to an electrical cable  116  to allow for provision of electrical power to the wellhead equipment  110  as well as to equipment in the subsea well  100 . The electrical cable  116  runs from the wellhead equipment to a remote power source, which can be located underwater, on a sea platform, or on a marine vessel. 
         [0020]    In accordance with some embodiments, a lubricator  118  is attached to the BOP  112 , where the lubricator  118  has an internal chamber that initially contains the electrically-activated tool that is to be deployed into the subsea well  100 . Although the example implementation shows the lubricator  118  as being attachable to the BOP  112 , it is noted that the lubricator  118  can be attached to other structures of the wellhead equipment  110  in other implementations. 
         [0021]    The upper end of the lubricator  118  is attached to a compliant guide  120 , which is a flexible tubing extending from a marine vessel  122  located at the sea surface  124 . The compliant guide  120  has an inner bore in which the coiled tubing for deploying the electrically-activated tool into the subsea well  100  is located. 
         [0022]      FIG. 2  is a schematic diagram that shows an electrically-activated tool  200  located inside an inner chamber  202  of the lubricator  118 . Also,  FIG. 2  shows the electrically-activated tool  200  being attached to a coiled tubing  204  that extends through the inner bore of the compliant guide  120 . 
         [0023]    In operation, an assembly that includes the lubricator  118  and the electrically-activated tool  200  contained inside the lubricator  118  is deployed from the marine vessel  122  to the well site shown in  FIG. 1 . The lubricator  118  is then attached to the BOP  112 . In addition, the compliant guide  120  is attached to the lubricator  118 , which allows the coiled tubing  204  to attach to the electrically-activated tool  200 . The electrically-activated tool  200  is then lowered into the subsea well  100  on the coiled tubing  204  through the wellhead equipment  110 . 
         [0024]    Once lowered into the subsea well  100 , the electrically-activated tool  200  is positioned inside the production tubing  106 . In some embodiments, the electrically-activated tool  200  is a pump such as an electrical submersible pump (ESP). In the ensuing discussion, reference is made to an ESP—however, in alternative embodiments, other types of electrically-activated tools can be used. 
         [0025]    Once the ESP  200  is positioned in the production tubing  106 , the ESP  200  can be activated to start pumping fluids drawn into the subsea well  100  to the surface. Fluids flowed to the wellhead equipment  110  are directed into conduits (not shown) to carry the fluids to another location, such as to a sea surface platform or marine vessel, or to an underwater storage facility. 
         [0026]    Over the life of the ESP  200 , it is possible that the ESP  200  may fail, such that the ESP  200  would have to be replaced.  FIG. 1  further shows another assembly including a replacement lubricator  126  and a replacement ESP contained in the replacement lubricator  126  that can be lowered from the marine vessel  122  to replace the existing lubricator  118  and ESP  200 . If a fault or failure of ESP  200  is detected, the ESP  200  is retrieved from the subsea well  100  into the lubricator  118 . The lubricator  118  (containing the ESP  200 ) can then be detached from the BOP  112  and set to the side, and the replacement lubricator  126  (which contains the replacement ESP) is then attached to the BOP  112  in place of the lubricator  118 . The lubricator  118  and ESP  200  can then be retrieved to the marine vessel  122  for repair or disposal. 
         [0027]    Next, the compliant guide  120  is attached to the replacement lubricator  126 . The coiled tubing  204  inside the compliant guide  120  is then attached to the replacement ESP, and the coiled tubing  204  can be used to lower the replacement ESP into the subsea well  100 . 
         [0028]    In this manner, a relatively convenient and flexible mechanism is provided for replacement of an ESP or other type of electrically-activated tool that has been deployed into the subsea well  100 . 
         [0029]    As noted above, the coiled tubing  204  can be provided without an electrical cable to reduce the complexity and cost of the coiled tubing. In such an embodiment, power is not provided through the coiled tubing  204 , but rather is provided by an alternative mechanism.  FIG. 1  further shows that the production tubing  106 , which is positioned downhole in the subsea well  100 , is provided with a connection sub  130  that is configured to make a connection (electrical connection and optionally a hydraulic connection) with a corresponding connection mechanism  206  on the ESP  200 . Also, the production tubing  106  has an internal upper seal bore  132  and a lower seal bore  134  for sealing engagement with corresponding upper and lower sealing elements  208  and  210  provided on the ESP  200 . 
         [0030]    Thus, once the ESP  200  is positioned at the correct depth inside the production tubing  106 , the connection mechanism  206  on the ESP  200  engages with the connection sub  130  of the production tubing  106 . Also, the sealing elements  208  and  210  sealingly engage the corresponding upper and lower seal bores  132  and  134  such that proper fluid seals are established between the ESP  200  and the inner wall of the production tubing  106  to allow for proper operation of the ESP  200 . 
         [0031]      FIG. 3  illustrates an enlarged view of portions of the production tubing  106  and the ESP  200 . In some embodiments, the ESP  200  is provided with two motors  302  and  304  to provide redundancy. One of the motors  304  can be used for operating the ESP  322  until a fault or failure is detected, at which point the other of the motors  302 , is selected for operating the ESP  320 . 
         [0032]      FIG. 3  further shows details of the connection sub  130  (on the production tubing  106 ) for making connection with the corresponding connection mechanism  206  on the ESP  200 . The connection sub  130  includes an electrical connector assembly  130 A for making a wet electrical connection with a corresponding electrical connector  206 A that is part of the connection mechanism  206  on the ESP  200 . In addition, in some embodiments, the connection sub  130  further includes a hydraulic connector assembly  130 B for connection to a corresponding hydraulic connector  206 B that is part of the connection mechanism  206  on the ESP  200 . 
         [0033]    The electrical connector assembly  130 A is connected to an electrical cable  306  that runs outside the production tubing  106 , and the hydraulic connector assembly  130 B is connected to a hydraulic control line  308  that also runs outside the production tubing  106 . Although the connection sub  130  and the connection mechanism  206  are depicted as including both electrical and hydraulic connectors, it is noted that in alternative embodiments, the hydraulic connectors can be omitted. 
         [0034]    In the ESP  200 , a switch sub  305  is provided between the upper motor  302  and the lower motor  304 . The switch sub  305  is used to selectively activate one of the motors  302  and  304 . In some embodiments, the selective switching between the upper motor  302  and the lower motor  304  is accomplished by using a hydraulic mechanism actuated by hydraulic pressure provided through the hydraulic control line  308 . In alternative embodiments, instead of using a hydraulic mechanism to switch between the upper and lower motors  302  and  304 , an electrically-activated switch mechanism in the switch sub  305  can be used instead. 
         [0035]    The upper motor  302  is connected to the switch sub  305  by a set  310  of three electrical lines that carry the three phases of high-voltage power. This connection may be a Wet Mate connection made between  305  and  302  in the wellbore  106 . This would facilitate the separate installation of lower pump section  600  from upper pump section  602 . Similarly, a set  312  of three electrical lines connect the lower motor  304  to the switch sub  305 . Power is provided to a selected one of the motors  302  and  304  over a respective set  310  and  312  of electrical lines depending on which of the motors has been selected by the switch sub  304  for activation. 
         [0036]    In accordance with some embodiments, the hydraulic control line  308  provides hydraulic pressure to allow for selective switching between the upper and lower motors  302  and  304 . If the well operator detects that the upper motor  302  has failed, for example, then hydraulic pressure can be applied through the hydraulic control line  308  to cause the switch sub  305  to switch to the lower motor  304  (such that power from the electric cable  306  is provided through the switch sub  305  to the lower motor  304  through the set  312  of electrical lines). Conversely, a switch from the lower motor  304  to the upper motor  306  can be performed if it is detected that the lower motor  304  is faulty or has failed. 
         [0037]      FIGS. 4 and 5  illustrate components within the switch sub  305  that are used for switching between the upper motor  302  and the lower motor  304 . Two sets of contact terminals are shown in  FIG. 4 : a first set that includes contact terminals M 1 A, M 1 B, and M 1 C; and a second set that includes contact terminals M 2 A, M 2 B, and M 2 C. The first set of contact terminals M 1 A, M 1 B, M 1 C are connected to the corresponding electrical lines of the first set  310  (shown in  FIG. 3 ). Similarly, the second set of contact terminals M 2 A, M 2 B, and M 2 C are connected to the second set  312  of electrical lines (shown in  FIG. 3 ). 
         [0038]      FIG. 4  also shows a set of movable electrical connection pins  402 A,  402 B, and  402 C (which can be part of a hydraulically movable sleeve, for example), which are designed to electrically contact either the first set of contact terminals M 1 A, M 1 B, M 1 C, or the second set of contact terminals M 2 A, M 2 B, M 2 C, depending upon the positions of the corresponding connection pins  402 A,  402 B, and  402 C. In  FIG. 4 , the connection pins  402 A,  402 B,  402 C are shown in a lower position to make electrical contact between termination points  404 A,  404 B, and  404 C and the corresponding contact terminals M 2 A, M 2 B, and M 2 C. The termination points  404 A,  404 B, and  404 C are electrically connected to the three-phase power voltages provided by the electrical cable  306 . 
         [0039]    In the position of  FIG. 4 , power from the electrical cable  306  ( FIG. 3 ) is provided to the contact terminals M 1 A, M 1 B, and M 1 C. This in turn causes power to be provided to the second set  312  of electrical lines ( FIG. 3 ) to provide power to the lower motor  304 . 
         [0040]    On the other hand, as shown in  FIG. 5 , the movable connection pins have been moved upwardly (by hydraulic actuation using the hydraulic control line  308  and hydraulic connectors  130 B and  206 B of  FIG. 3 ) to their upper positions for making electrical contact with the first set of contact terminals M 1 A, M 1 B, and M 1 C. In the position of  FIG. 5 , electrical power is provided from the electrical cable  306  ( FIG. 3 ) and through the termination points  404 A,  404 B,  404 C, contact terminals M 1 A, M 1 B, M 1 C, and first set  310  ( FIG. 3 ) of electrical lines to the upper motor  302 . 
         [0041]      FIG. 6  shows the ESP  200  according to one example embodiment in greater detail. Although a specific arrangement of components of the ESP  200  is shown in  FIG. 6 , it is noted that in an alternative embodiment, a different arrangement of components can be employed in the ESP  200 . In addition to the switch sub  305  and upper and lower motors  302  and  304 , the ESP  200  also includes an upper pump  320  that is powered by the upper motor  302 , and a lower pump  322  that is powered by the lower motor  304 . The ESP  200  includes a lower pump section  600  (which includes the lower motor  304  and lower pump  322 ) and an upper pump section  602  (which includes the upper motor  302  and upper pump  320 ). 
         [0042]    Referring further to  FIG. 8 , it is assumed that the switch sub  305  has been actuated to activate the lower motor  304  (such that the lower pump section  600  is active and the upper pump section  602  is inactive). In the lower pump section  600 , a pump intake  324  is configured to accept input fluid flow (arrows  802  in  FIG. 8 ) into the lower pump section  600 . The lower pump  322  causes fluid to flow upwardly past the sealing elements  210  for discharge through a lower pump discharge  326  (arrows  804 ). The fluid that is discharged from the lower pump discharge  326  is flowed further upwardly, as shown by arrows  806 ,  808 , and  810 , and  812  in  FIG. 8 . 
         [0043]    Arrows  806  indicate that the fluid output from the lower pump discharge  326  is flowed into a lower portion of the switch sub  305 . The fluid then exits the upper portion of the switch sub  305  (as indicated by arrows  808 ) and the fluid is further received in an upper autoflow sub (arrows  810 ). Fluid then exits at the top of the ESP  200  (arrows  812 ) above the upper sealing elements  208 . 
         [0044]      FIG. 7  shows operation of the ESP  200  when the upper motor  302  and upper pump  320  are operating, and the lower motor  304  and lower pump  322  are inactive. Fluid flows into a lower autoflow sub  328  (arrows  702 ), which then exits through the lower pump discharge  326  (arrows  704 ). The fluid then continues into the lower portion of the switch sub  305  (arrows  706 ), and out of the upper portion of the switch sub  305  (arrows  708 ). The fluid that flows out of the switch sub  305  is then directed through the upper pump intake  330  (arrows  710 ), which then is pumped out of the top of the ESP  200  (arrow  712 ). 
         [0045]    The ESP  200  depicted in  FIGS. 6-8  further include other components, including another discharge sub (represented as “D”) and another autoflow sub (represented as “A”), which are used for fluid flow in other operations of the ESP  200 . 
         [0046]    Although the embodiments discussed herein employ a dual ESP system that has two pumps, it is noted that in an alternative embodiment, a single ESP system can be used that includes just a single pump. In addition the dual ESP system may be assembled in the production tubing  106  separately. Lower pump system  600  may be installed locating the switch sub  305  to connection mechanism  130  and sealing element  210  to seal bore  134 . Upper pump assembly  602  may then be installed locating upper motor  302  to switch sub  305  and sealing element  208  to seal sub  132 . Such an arrangement facilitates a small lubricator  118 . In addition, instead of using a wet connect mechanism, alternative embodiments can employ other types of electrical connection mechanisms, such as inductive coupler mechanisms. 
         [0047]    While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover such modifications and variations as fall within the true spirit and scope of the invention.