Abstract:
A switch mechanism is provided for inclusion in a downhole production string located in a wellbore. The switch mechanism includes an electrical power input and at least two electrical power outputs. In addition, the switch mechanism includes an actuator mechanism which is capable of being actuated from a position remote from the wellbore to selectively move between at least two positions. The movement thereby provides a selective electrical connection between the input and one of the outputs when the actuator is in one of the at least two positions.

Description:
FIELD OF THE INVENTION 
     The present invention relates to an apparatus and method for use downhole to provide power to two or more pumps and more particularly relates to a switch mechanism operable to allow a single power cable to supply electrical power to two or more downhole electrical motors alternatively. 
     BACKGROUND 
     Many oil and gas wells must be provided with artificial lift in order to extract the hydrocarbons in an effective manner, otherwise the relatively low natural reservoir pressure (particularly in the middle and latter years of some wells) is not sufficient to flow the well. Conventionally, the artificial lift can be provided by a variety of methods including injection of CO2 into the well to force the hydrocarbons up to the surface and by providing downhole pumps to suck in the hydrocarbons and pump them up production tubing to the surface. An Electrical Submersible Pump (ESP) is a form of artificial lift pump designed to draw fluid from a well in the absence of pressure to suit the production rate required. Typically ESPs, in the oilfield, have been run as single units on the end of the production tubing. A power cable, attached to the electrical motor unit of the ESP extends to the surface of the well alongside the production tubing and terminates at the wellhead. 
     The power cable will often need to be fed through a packer (a downhole barrier adapted to seal the annular gap between the production tubing and the casing) prior to extending to the surface of the well where the power cable also needs to be fed through the wellhead. At both of these junctions, the power cable usually has to be deployed with an electrical penetrator which seals the cable into the wellhead and packer. It should be noted however that not all ESP wells use packers but all require wellheads and such a typical/conventional configuration of a well having an ESP deployed therein is shown in  FIG. 1 . 
     In more recent years, it has become more customary for an operator to want to use a dual ESP configuration, where one ESP is run on top of the other, with a spacing therebetween. This configuration allows one ESP unit to be operated or run to the end of its life and then the second ESP unit is switched on. The benefits of dual ESP systems are considerable in terms of saved workover (well completion replacement), costs and avoidance of oil well downtime. 
     Conventional dual ESP configurations require a dedicated power cable from each of the dual ESPs to the surface of the well and therefore two power cables are required from the ESP&#39;s to the surface. 
     The power cable feed for the lower ESP motor extends from a plug-in connection at the lower ESP motor, up beyond the upper ESP and is joined by the power cable feed for the upper ESP. From there, both cables extend to the surface of the well and such a typical/conventional configuration of a well having a dual ESP system deployed therein is shown in  FIG. 2 . 
     In wells where the power cable has to pass through a packer as well as through the wellhead, special electrical “penetrators” (units which seal the power cable into a steel body) are required. 
     Dual ESP systems therefore require two penetrators, both for the packer and for the wellheads. Unfortunately, standard wellheads and packers are manufactured with only a single penetrator and cannot be modified to accept twin penetrators. Accordingly, packers and wellheads have to be specially manufactured to suit twin penetrators. 
     Accordingly, for new wells, packers and wellheads can be specially ordered to accommodate the twin penetrator requirement. However, existing wells would require a conversion and this leads to significant costs due to the large variety of wellhead types and the engineering required. Furthermore, the existing customer owned and very expensive wellheads and packers would therefore be scrapped. 
     This extra (significant) cost plus the associated lead time in obtaining such new and special wellheads currently makes conversion to dual ESPs non-viable for many existing wells or at least, presents a barrier to conversion to duals ESP systems. 
     It would therefore be desirable if the existing wellhead (and packer if required) can be utilised; if this was the case then conversion to dual ESPs becomes more viable and presents a significant opportunity to improve ESP viability in all manner of wells. 
     SUMMARY OF THE INVENTION 
     According to a first aspect of the present invention there is provided a downhole switch mechanism for inclusion in a production string located in a wellbore, the downhole switch mechanism comprising:
         an inlet for electrical power;   at least two outlets for electrical power; and   an actuator mechanism which is capable of being actuated from the surface of the wellbore to selectively move between at least two positions in order to provide a selective electrical connection between the said inlet and one of the said outlets.       

     According to the first aspect there is provided a method of powering at least two electrically operated devices associated with or included in a production string located downhole in a wellbore via a single electrical cable, the method comprising the steps of:
         providing a switch mechanism in the production string, the switch mechanism being supplied with electrical power from the surface of the wellbore by means of the single electrical cable and further being coupled to at least two downhole devices; and   actuating, at the surface, the switch mechanism to move between two or more positions, each position being associated with one of the said downhole devices,   such that electrical power is selectively supplied from the single electrical cable to the selected downhole device.       

     Preferably, the switch mechanism is incorporated into the production string before it is run into the wellbore. 
     Preferably, the actuator mechanism further comprises a switch arm mechanism moveable between the at least two positions, and more preferably, each position is associated with one of the said electrical power outlets. Typically, the actuator mechanism is capable of being actuated from the surface, of the wellbore to selectively move the switch arm mechanism between the two positions. 
     Typically, the downhole devices comprise electrically operated downhole pumps and more preferably the downhole pumps are electrically submersible pumps (ESPs). 
     Preferably, the switch arm is actuated by means of an actuator mechanism. Preferably, the actuator mechanism is also powered from the surface. In one preferred embodiment, the actuator mechanism comprises a hydraulic fluid powered actuator mechanism and in this preferred embodiment, the actuator mechanism comprises a hydraulic cylinder and piston arrangement, wherein fluid can be injected into or withdrawn from the hydraulic cylinder in order to move the piston. In this preferred embodiment, the piston is mechanically coupled to the switch arm. 
     Preferably, the switch mechanism is located downhole in the wellbore below a wellhead of the wellbore, where the wellhead of the wellbore is typically located at the surface thereof. Typically, where an annular sealing device such as a packer is included in the production string, the switch mechanism is typically located below the annular sealing device. 
     Typically, a first branch electrical cable is arranged to connect the first outlet of the switch mechanism to a first ESP and a second branch electrical cable is arranged to connect the second outlet of the switch mechanism to a second ESP. Preferably, the single electrical cable is electrically coupled to the inlet of the switch mechanism such that the single electrical cable supplies power from the surface of the wellbore to the inlet of the switch mechanism, through the switch arm to the selected downhole ESP. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings. 
         FIG. 1  shows a typical ESP configuration. 
         FIG. 2  shows a dual ESP bypass system. 
         FIG. 3A  is a schematic view of a hydrocarbon well system comprising an upper half of completion and production equipment. 
         FIG. 3B  is a schematic view of a first embodiment of a lower half of completion and production equipment incorporating a dual ESP system and a downhole switch mechanism in accordance with the present invention for use with the upper half of  FIG. 3A . 
         FIG. 3C  is a schematic view of a second embodiment of a lower half of completion and production equipment incorporating a dual ESP system and a downhole switch mechanism in accordance with the present invention for use with the upper half of  FIG. 3A . 
         FIG. 3D  is a schematic view of a third embodiment of a lower half of completion and production equipment incorporating a dual ESP system and a downhole switch mechanism in accordance with the present invention for use with the upper half of  FIG. 3A . 
         FIG. 3E  is a schematic view of a fourth embodiment of a lower half of completion and production equipment incorporating a dual ESP single by-pass and single can system and a downhole switch mechanism in accordance with the present invention for use with the upper half of  FIG. 3A . 
         FIG. 3F  is a schematic view of a fifth embodiment of a lower half of completion and production equipment incorporating a dual ESP dual can system and a downhole switch mechanism in accordance with the present invention for use with the upper half of  FIG. 3A . 
         FIG. 4A  is a schematic view of a downhole switch mechanism in accordance with the present invention and used in the embodiments shown in  FIGS. 3B ,  3 C and  3 D. 
         FIG. 4B  is a schematic view of the downhole switch mechanism of  FIG. 4A  in a first configuration adapted to provide power to an upper ESP unit. 
         FIG. 4C  is a schematic view of the downhole switch mechanism of  FIG. 4A  in a second configuration adapted to provide power to a lower ESP unit. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 3A  shows the upper portion of a typical downhole completion and production system as comprising a wellhead  10  located at the surface with a conventional single penetrator wellhead hanger  12 . A single  3  phase electrical cable  14  passes through the single penetrator  12  and down towards the lower half of the well shown for instance in  FIG. 3B . A suitable diameter hydraulic cable  16  such as ¼″ diameter also passes through the single penetrator  12  in a conventional manner, but as is also conventional, standard single penetrator wellhead hangers  12  are already provided with the provision or ability to have a relatively small conduit hydraulic line such as ¼ ″ outer diameter conduit to pass through them (as well as a much larger diameter electrical cable  14 ). As is also conventional, the electrical cable  14  and hydraulic line or conduit  16  are secured to production tubing  18  by means of standard cable protectors  20  which are provided at each joint between each length of production tubing  18 , that is every 30 feet. As is also conventional, a standard production packer  22  having a single penetrator therein is provided toward the lower half of the upper half of the completion  8  where the single penetrator of the packer  22  allows the electrical cable  14  (and the hydraulic conduit line  16 ) to pass through the body of the packer  22 . 
     An embodiment of an apparatus and a method for distributing power downhole with only one electrical cable in accordance with the present invention is shown in  FIG. 3B  where  FIG. 3B  generally shows the lower half of a downhole completion  9 B. The lower completion equipment  9 B comprises production tubing  18  and a pair of ESPs  24 BU,  24 BL where the production tubing  18  continues on to the bottom of the well to allow the transport of hydrocarbons from the bottom of the well up to the surface. The pair of ESPs  24 BU,  24 BL shown in  FIG. 3B  are arranged in parallel with the production tubing  18  and, for the configuration shown in  FIG. 3B , the pair of ESPs  24 BU,  24 BL would typically remain dormant until the hydrocarbons had been produced from the bottom of the well and can no longer be produced from that deep region. At such a point, the operator may take the decision to activate the lower ESP  24 BL such that it pumps hydrocarbons from its locality upwards through outlet pipe  28  and into the inverted Y-shaped branch joint  30  and then up through the rest of the production tubing  18  to the surface. 
     A hydraulic switch module  26 B is conveniently located close to the upper ESP  24 BU. 
     In general, the hydraulic switch  26 B can be actuated with hydraulic fluid supplied through the hydraulic line  16  from the surface to move an electrical connector or switch arm  38  such that the electrical power delivered through the electrical cable  14  can be delivered to either the upper ESP  24 BU or the lower ESP BL. More details of the hydraulic switch  26  are shown in  FIGS. 4A ,  4 B and  4 C and will now be described. 
       FIG. 4A  shows the hydraulic switch  26  as comprising a single acting piston  32  with a heavy duty return spring  33  located within a hydraulic fluid cylinder or piston chamber  34 . The hydraulic line  16  (which is purged before use) extends from the surface down to the switch module  26 B and connects directly to the piston chamber  34 . Accordingly, hydraulic fluid from the surface can be delivered through the hydraulic line  16 U and injected into the piston chamber  34  or withdrawn from it in order to move the position of the piston head  32  to the left or right of the position shown in  FIG. 4A . The outer end of the piston  32  is mechanically coupled at location  36  to a driver mechanism in the form of a switch arm  38  shown in dotted lines in  FIGS. 4B and 4C . The switch arm  38  is electrically coupled via contacts A, B and C to the three phases of the electrical cable  14 . Accordingly, movement of the piston  32  directly moves the switch arm  38  and thus the switch contacts A, B and C between position  1  and position  2 . 
     The motor of the upper ESP  24 U comprises  3  electrical power inputs D, E, F and the motor of the lower ESP  24 L comprises  3  electrical power inputs G, H, I. 
     The hydraulic switch  26  has two configurations or positions:
         position  1  shown in  FIG. 4B  where the switch arm  38  electrically couples the three phases A, B and C of the electric cable  14  to the three phases D, E and F of the upper ESP  24 U. In this position, the three phases G, H and I of the lower ESP  24 L are shown as being isolated. Accordingly, position  1  provides full power to and operation of the upper ESP  24 U whilst the lower ESP  24 L remains dormant.   position  2  of the switch arm  38  is shown in  FIG. 4C  where the switch arm  38  has been moved by the piston  32  via the mechanical coupling  36  such that the three phases A, B and C of the electric cable  14  are now electrically coupled to the three phases G, H and I of the lower ESP  24 L. Accordingly, position  2  provides full power to and operation of the lower ESP 24 L whilst the upper ESP  24 U becomes dormant.       

     Consequently, the operator can, from the surface, select which of the two ESPs  24 BL,  24 BU to operate by actuating the hydraulic switch  24 B with surface control equipment to move the piston  32  against the return spring  33  to move the switch arm  38  to the desired position  1  or  2 , all the while only having to run one electric cable from the surface down to the dual ESPs  24 BU,  24 BL. The operator can lock the pressure in the hydraulic fluid at the surface to hold the position  1  or  2  of the switch arm  38 . 
     An alternative lower half of the completion  9 C is shown in  FIG. 3C  where the lower ESP  24 CL constitutes the lowermost portion of the completion  9 C and its output feeds straight into the lowermost end of the production tubing  18 . As can be seen in  FIG. 3C , the upper ESP  24 CU and the switch  26 C are arranged in a similar manner to the upper ESP  24 BU and the switch  26 B of the system  9 B of  FIG. 3B . 
     A further alternative arrangement of ESPs is shown in system  9 D in  FIG. 3D  where only one ESP  24 DU is shown but where there is another lower ESP  24 DL located much further down the wellbore and which is supplied with electrical power via electric cable  14 L. The main difference, however, between the ESP  24 DU shown in  FIG. 3D  and the ESP  24 BU shown in  FIG. 3B  is that the hydraulic switch  26 D is shown as being located at the upper most end of the ESP  24 DU rather than being located mid-way down the ESP  24 BU. 
       FIG. 3E  shows a further alternative arrangement of ESPs  24 EU,  24 EL where the difference compared to the system  9 B in  FIG. 3B  is that the lower ESP  24 EL is enclosed within a can or housing  40 EL. The can  40 EL comprises a sealed cap  42 E at its upper most end and the lower end of the can  40 EL is attached to the lower section of production tubing  18 L. The can  40 EL acts to isolate the reservoir zone served by the lower ESP  24 EL from the reservoir zone served by the upper ESP  24 EU. Accordingly, the system  9 E provides a dual ESP with single bypass and single can system for operation in dual zones and the hydraulics switch  26 E can be operated as previously described to switch on either of the ESPs  24 EU,  24 EL to pump reservoir fluid from the desired respective zone. 
     A further alternative arrangement of ESPs  24 FU,  24 FL is shown in  FIG. 3F  where the system  9 F shown therein again comprises a pair of ESPs  24 FU,  24 FL provided with respective cans  40 FU,  40 FL where the lower end of the upper can  40 FU is connected to a middle section of production tubing  18 M and the lower end of that production tubing  18 M is connected to the upper end of the sealed cap  42 FL of the lower can  40 FL. The lower end of the lower can  40 FL is connected to the upper end of the lower production tubing section  18 L and the switch  26 F is located above the upper ESP  24 FU, and the sealed cap  42 FU of the upper can  40 FU. Accordingly, a first electric power cable  14 M branches out of the hydraulic switch  26 F to deliver power to the upper ESP  24 FU and a second electric cable  14 L branches out of the hydraulic switch  26 F to provide power to the lower ESP  24 L but, as with the previous embodiments, only one electric cable  14 U and one hydraulic conduit  16 U are required to be run from surface to the downhole hydraulic switch  26 F. Accordingly, the system  9 F shown in  FIG. 3F  provides redundancy in a single zone reservoir in that reservoir fluids can be pumped up through the lower production string  18 L by either the lower ESP  24 FL or the upper ESP  24 FU and up through the upper production string  18 U and therefore redundancy is provided if either ESP  24 FL,  24 FU were to fail. 
     Accordingly, the embodiments described herein provide the great advantage that power can be remotely switched between an upper ESP  24 U and a lower ESP  24 L where the power is supplied via one electric cable  14  and this provides the further advantage that only one power cable  14  is required to penetrate the wellhead  10  and therefore allows existing standard wellhead equipment  10  to remain in place, unlike the prior art dual ESP system shown in  FIG. 2 . Furthermore, if a packer is present, only single penetrators are required at both the wellhead  10  and packer  22 , meaning both of these penetrators and the associated wellhead  10  and packer  22  are standard equipment which thereby minimises the costs and manpower required to install the system (unlike the non-standard wellhead hanger/bonnet twin penetrator and the non-standard production packer having a twin penetrator shown in  FIG. 2 ). 
     Importantly, although an additional hydraulic line  16  to surface is required over a prior art single ESP system such as that shown in  FIG. 1 , conventional wellheads  10  and packers  22  are already furnished with small bore feedthrough porting for various applications to allow hydraulic lines such as line  10  to be passed therethrough. Furthermore, as the cost of rig time is so high, the switch  26  and the associated cabling and conduit arrangement will have the added benefit of significant time saving. 
     Importantly, it should be noted that the downhole switch  26  can be located anywhere under the wellhead  10  but, the lower it is positioned in the well, the less cable  14  is deployed downhole which means lower cabling costs. In fact, the choice to position the switch  26  directly under the wellhead  10 , or at the upper dual ESP  24 U will differ from case to case. Cable  14  is more vulnerable the deeper it goes so some users may wish to double the cable  14  on the underside of the wellhead  10  to maximize the reliability of the system and to avoid the potential failure on the cable  14  leading to both ESP units  24 U,  24 L being inoperable. Typically, if a packer  22  is used the cable  14  below the packer  22  is more vulnerable to downhole conditions than the cable  14  above the packer. Accordingly, the choice of positioning the switch  26  above or below the packer  22  will be made on a case by case basis depending on the operator&#39;s requirements. 
     If desired, the switch  26  could be modified by those skilled in the art without departing from the scope of the invention to provide third and fourth positions to allow further ESPs  24  to be added if, for instance, a triple or quadruple ESP  24  system was required by an operator. 
     Accordingly, the key benefits of embodiments of the present invention are:
         1. Only one power cable  14  to surface is required and thus the cable  14  cost is potentially halved;   2. Only require a single penetrator at packer  22  and thus a standard ESP packer  22  can be used;   3. Only require a single penetrator  12  at wellhead  10  and thus a standard ESP wellhead  10  can be used, giving greater flexibility for hanger size;   4. Standard protector clamps  20  can be used (in the case of a deep set switch  26 );   5. Minimal cost and disruption to convert to dual ESPs  24 U,  24 L thus benefiting from improved cost improvements on well production; and   6. Brings in the potential to deploy more than two ESPs  24 U,  24 L downhole such as triple ESP systems or quadruple ESP systems.       

     Modifications and improvements may be made to the embodiments hereinbefore described without departing from the scope of the invention. For instance, the hydraulically operated switch  26  could be modified or replaced with an electrical solenoid actuator that could be operated from the surface by, for instance, modulating instructions/control signals onto the three phase electrical supply provided through the electrical cable  14  and this would have the advantage that the hydraulic line  16  could then be omitted and such an electrical solenoid actuator could be powered from the electrical cable  14  itself.