AU2011255214A1

AU2011255214A1 - Mating unit enabling the deployment of a modular electrically driven device in a well

Info

Publication number: AU2011255214A1
Application number: AU2011255214A
Authority: AU
Inventors: Philip Head
Original assignee: Artificial Lift Co Ltd
Current assignee: Artificial Lift Co Ltd
Priority date: 2010-05-18
Filing date: 2011-05-19
Publication date: 2012-12-06
Also published as: US20130062050A1; CA2799839A1; GB2494317A; WO2011146949A3; WO2011146949A2; NO20121431A1; GB201220646D0

Abstract

An electric pump assembly is provided in a well, the pump comprising an electric motor module having a first outer housing and a first mating means, an electric pump module having a pump inlet and a pump outlet, and a second outer housing and a second mating means. In one aspect, the electric motor module and electric pump module are capable of being reversibly joined together by the first and second mating means, as the electric motor module includes a first rotating member that is capable of rotating relative to the first outer housing, and the electric pump module includes a second rotating member that is capable of rotating relative to the second outer housing. In this way, the first rotating member and second rotating member can transfer torque when the electric motor module and electric pump module are joined. In another aspect, a flowpath is provided in each module, the flowpaths fluidly communicating when the modules are joined.

Description

WO 2011/146949 PCT/ZA2011/000035 MATING UNIT ENABLING THE DEPLOYMENT OF A MODULAR ELECTRICALLY DRIVEN DEVICE IN A WELL Field of the invention 5 This invention relates to a method of deploying a modular electrical submersible powered fluid transducer system, such as a gas compressor or an electrical submersible pump, generally known as an ESP, in an oil and/or gas production well. 10 Background of the invention The disposing in wells of electrical submersible systems has been done for many years using jointed tubular conduits with an electrical motor, and a fluid transducer connected to the bottom of the jointed tubing. Consecutive joints of tubular conduits are connected and lowered into a well with the 15 assistance of a rig mast and hoisting equipment, whilst unspooling and connecting to the outer diameter of the tubing a continuous length of electrical power transmission cable. This method of disposing the electrical submersible fluid transducer system is well know to those familiar with the art of producing non-eruptive sources of oil and gas from the subterranean 20 environment. The retrieval of these electrical submersible fluid transducer systems is also commonly accomplished by pulling the jointed tubing out of the well simultaneously with the electrical submersible motor and fluid transducer system and the electrical power transmission cable. The following prior art references are believed to be pertinent to the invention 25 claimed in the present application: U.S. Pat. Nos. 3,939,705; 4,105,279; 4,494,602; 4,589,717; 5,180,140; 5,746,582 and 5871,051; International patent application No. W098122692 and European patent specifications Nos. 470576 and 745176. U.S. Pat. Nos. 3,835,929, 5,180,140 and 5,191,173 teach the art of deploying and retrieving an electrical submersible 1 WO 2011/146949 PCT/ZA2011/000035 system in oil wells using coiled or continuous tubing. These coiled tubing disposal methods often use large coiled tubing spool diameters owing to the radius of curvature possible of the continuous tubing. Hence the surface spooling devices that these systems require to inject and retrieve the 5 continuous tubing are cumbersome, and require special surface and subterranean equipment for deployment and intervention. Other previous art disclosed in the literature teaches the disposal and retrieval of the subterranean electrical fluid transducer system with wireline 10 or wire rope as structural support for simultaneously disposing the electrical power transmission cable with the system. Hence these wireline methods and apparatus involve the use of large and unique surface intervention equipment to handle the weight and spool used for the electrical power cable and the wire rope to be run in the well. U.S. Pat. No. 5,746,582 15 discloses the retrieval of a submersible pumps whilst leaving an electrical motor and cable in a well. Hence the method of U.S. Pat. No. 5,746,582 teaches the retrieval and deployment of the mechanical portion of an electrical submersible fluid transmission system whilst leaving the electrical motor and other component parts of the electrical submersible system 20 disposed in the disposal of the electrical motor separately from the electrical power transmission cable. In the case of artificially lifted wells powered with electrical submersible motor systems, the current art is to dispose the required transducer assembly, for example a pump or compressor assembly, with an electrical motor and electrical power cable simultaneously into the 25 well with a supporting member. This supporting member is jointed tubing from a surface rig, a coiled tubing unit with continues tubing or braided cable. The tubing or a braided cable is required as the electrical power cable is not able to support its own weight in the well and hence must be connected and disposed in the well with a structural member for support. In 2 WO 2011/146949 PCT/ZA2011/000035 the case of jointed pipe deployed from a rig, the power cable is attached to the electrical motor on surface, and the cable is attached to the tubing as the electrical motor, transducer, and tubing are disposed into the well casing or tubing. The attachment of the cable to the tube is done by the use of steel 5 bands, cast clamps, and other methods known to those familiar with the oil and gas business. In other methods, the power cable is placed inside of continuous tubing or attached to the outside of continuous tubing with bands as taught by U.S. Pat. No. 5,191,173. This continuous tubing is often referred to in the industry as coiled tubing. U.S. Pat. No. 3,835,929 teaches 10 the use of the continuous tubing with the electrical power transmission cable inside of the tube. In all cases where electrical submersible fluid transducers systems are disposed and retrieved from wells the electric motor and electrical power transmission cable are deployed or retrieved simultaneously. 15 It is well known to those familiar with electrical submersible power cable that the action of removing the cable from the well can result in damage to the electrical power transmission cable, in a variety of ways. The damage inflicted on the electrical power cable can be due to bending stresses 20 imposed on the cable during the disposal and retrieval. The conventional electrical power cable insulation, wrapping, and shields can develop stress cracks from the spooling of the cable over sheaves and spools devices used to deploy the cable. Another failure mode associated with submersible power transmission cable is caused form impact loads or crushing of the 25 cable as it is disposed or retrieved in the wells. It is also well known that gases found in subterranean environments impregnated the permeability of the electrical power transmission cable's insulation, wrapping and shields. This gas is trapped in the permeability of the insulation at a pressure similar to the pressure found inside the well. When the cable is retrieved from the 3 WO 2011/146949 PCT/ZA2011/000035 well the electrically powered transmission cable is exposed to ambient pressures. This will create a pressure differential between gas encapsulated in the cable insulation and the ambient surface pressure conditions. The rate of impregnated gas expansion from the higher pressure inside of the cable 5 insulation expanding towards the lower pressure of the ambient conditions can sometimes exceed the cable insulation permeability's ability to equalise the pressure differential. The result is a void, or stressing of the insulation, and premature failure of the cable. The requirement to retrieve and dispose the electrical power transmission cable with the electrical submersible fluid 1o traducer system also requires the use of specialised surface intervention equipment. This can require very large rigs, capable of pulling tubing, electrical power transmission cable, and electrical submersible fluid transducers. In the offshore environment these well intervention methods require semi-submersible drill ships and platforms. In the case of jointed 15 conduit deployed in a plurality of threaded lengths, normally 9-12 m each, the pulling equipment is a drilling or pulling rig at surface. In the case that the electrical power transmission cable and assembly are disposed connected to or in continuous tubing, a specialised coiled tubing rig is required at surface. This coiled tubing unit consisting of an injector head, a 20 hydraulic power unit, and a large diameter spooling device containing the continuous coiled tubing all located on the surface. This disposal and retrieval method requires significant space at the earth's surface or sea floor. The reasons for intervening in a well to retrieve or dispose an electrical submersible transducer system are well know to those familiar 25 with the art of fluid removing fluids from wells. There are at least two classical reasons for intervention in wells disposed with electrical submersible fluid transducer systems. These include the need to increase fluid production, or the need to repair the disposed electrical submersible power system. The reason for requiring increased fluid production is 4 WO 2011/146949 PCT/ZA2011/000035 dependent on many factors including but not limited to economical and reservoir management techniques discussed in the literature. The reasons for intervening for repair or to replace the electrical submersible fluid transducer systems are due to normal equipment wear and the subsequent 5 loss of fluid production capacity, catastrophic equipment failure, and changes in the fluid production capacity of the subterranean fluid reservoir. The equipment failures can be caused due to subterranean electrical failures in the electrical motor windings, electrical motor insulation degradation due to heat or mechanical wear, conductive fluid leaking into the motor, wear or 10 failure of the fluid transducer parts, wear of electrical motor bearings, shaft vibrations, changes in inflow performance of the reservoir, and other phenomena known to those familiar with the art of fluid production from wells. Therefore, it is often required to change out component parts of the electrical submersible fluid transducer system, but not necessarily the 15 electrical power transmission cable. However, owing to prior art the power cable is retrieved when the electrical motor or the motor seals fail. Summary of the invention According to the present invention, there is provided an electric pump 20 assembly as defined in the claims. In a first aspect, an embodiment provides an electric pump assembly in a well, comprising an electric motor module having an first outer housing and a first mating means, an electric pump module having a pump inlet and a 25 pump outlet, a second outer housing and a second mating means, the electric motor module and electric pump module capable of being reversibly joined together by the first and second mating means, the electric motor module includes a first rotating member that is capable of rotating relative to the first outer housing, and the electric pump module includes a 5 WO 2011/146949 PCT/ZA2011/000035 second rotating member that is capable of rotating relative to the second outer housing, such that the first rotating member and second rotating member can transfer torque when the electric motor module and electric pump module are joined. 5 In a second aspect, an embodiment provides an electric pump assembly in a well, comprising an electric motor module having an first outer housing and a first mating means, an electric pump module having a pump inlet and a pump outlet, a second outer housing and a second mating means, the 10 electric motor module and electric pump module capable of being reversibly joined together by the first and second mating means, the electric motor module including a first flowpath inside the first outer housing, the electric motor module including a second flowpath inside the second outer housing, such that the first and second flowpaths are brought into fluid 15 communication when the electric motor module and electric pump module are joined. Preferably, the electric motor module includes a first rotating member that is capable of rotating relative to the first outer housing, and the electric 20 pump module includes a second rotating member that is capable of rotating relative to the second outer housing, such that the first rotating member and second rotating member can transfer torque when the electric motor module and electric pump module are joined. 25 Brief description of the drawings Various illustrative embodiments of the invention will now be described, purely by way of example and without limitation to the scope of the claims, and with reference to the following figures, in which: 6 WO 2011/146949 PCT/ZA2011/000035 Figs. 1-3 show a side view of the production tubing, and of the ESP modules, before and after installation; Fig. 4 shows a side view of a module mating unit, coupled; 5 Fig. 5 shows a side view of a module mating unit, uncoupled; Fig. 6 shows a cross sectional view of the electric cable; io Fig. 7 shows a cross sectional view of one of the conductors within the cable; Figs 8 and 9 show a side view of another embodiment of the motor and an expansion tube, and a side view of that embodiment in operation in the 15 production tubing; and Figs. 10 - 14 show further embodiments wherein: Fig. 10 shows a side view of the production tubing, electrical power cable, 20 side pocket electrical connection are installed permanently in an oil or gas well; Fig. 11 shows a side view of the ESP modules; 25 Fig. 12 shows a side view of the production tubing, electrical power cable, side pocket electrical connection are installed permanently in an oil or gas well, with the ESP modules in there final installed position; Fig. 13 shows a side view of a module mating unit, coupled; and 7 WO 2011/146949 PCT/ZA2011/000035 Fig. 14 shows a side view of a module mating unit, uncoupled. Detailed description of the embodiments of Figures 1 - 9 5 Referring to figures 1 to 3, there is shown a well completion with casing 1 cemented into the wellbore. A packer 2 with elastomer seals 9 is set in the casing which includes a polished bore receptacle (PBR ) 3. The production tubing 4 stings into the PBR with a stinger 5 and seal 6. 10 A no go landing feature 8 is included to provide a reference stop point when installing the pump module 50. Pump module 50 consists of a stinger and pump inlet 64, a pump 66, and a pump outlet 67 and a mating unit 68. 15 Motor module 51 consist of a mating unit 69, a motor seal 70, a motor 67, and a sensor package 61 and umbilical interface 71. To deploy the pump 50 and motor 51, the pump 50 is first lowered down 20 the well on a wireline, the wireline terminating in a running tool that connects to the mating unit 68. The pump comes to rest when the stinger 64 reaches the landing feature 8, the stinger forming a seal against the polished bore receptacle inside stinger 5. When the surface operator detects that the pump has reached this point (for example by monitoring the weight 25 on the wireline or the length of wireline deployed), the running tool is released and the wireline extracted. The motor module package 51 may then be deployed, the motor 51 being suspended on an umbilical cable 71. When the motor module reaches the 8 WO 2011/146949 PCT/ZA2011/000035 pump module, the motor module's mating unit 69 engages with the pump module's mating unit 68. As well as suspending the motor during deployment, the umbilical 71 5 supplies the motor with electric power. Once installed with the pump module, the motor can be operated from the surface, the motor activating the pump so that well fluid from beneath the pump inlet 64 is drawn up through the pump 66, and exits through the pump outlet 67 and up through the production tubing 9 to the surface. 10 Referring to figures 4 and 5, this shows the mating unit in more detail, the lower housing body 100 has an internal bore 101, with a sealing surface 102 and internal spleens 103. On the upper half of the mating unit the outer housing 104 has a reduced diameter 105, and spines 106 at its lowest 15 extreme end which enables it to pass the seal diameter 102 and engage the splines 103 in the lower mating unit body 100. The seal 107 engages the bore 102 and seals the ID from the OD. In the lower mating unit is a shaft 110, mounted in bearings 111 and 112 20 which transmits torque. Its upper end is pointed 113 to enable engagement, and splined 114 to transmit the torque from the shaft 120 in the upper mating unit. The internal spines 121 on the upper shaft engage the spines 114 on the lower shaft. The upper shaft is also mounted in bearings 111 and 112. 25 Internal flow path consisting of drilled holes 130 and 131 enable fluid to pass from the lower side of the mating unit to the upper side of the mating unit when engaged. This enables the pump discharge from the lower pump to enter the pump inlet of the upped pump. If two pump modules are 9 WO 2011/146949 PCT/ZA2011/000035 required and deployed separately. The flow path is not required if the motor module is connected to the pump module Referring to figure 6, the umbilical 160 includes three conductors 161 5 arranged (spirally wound) in a triangular formation, held together in a insulating filler 162 (which may, for example, be extruded around the conductive cables). The conductive cables and filler are then surrounded by a composite fibre 164 such as Kevlar (R). The weight of the cable is supported by the conductors 161 themselves. The filler 162 and the 10 composite fibre 164 do not themselves provide any significant load bearing characteristics. The composite fibre 164 does though protect the body of the cable from damage from friction or pressure from other components as it is deployed down the well. Further, the spirally wound cabel arrangement results in a torque in the cable. The composite fibre 164 may 15 be wound so as to provide a torque reaction to this. Referring to figure 7, a single conductor in this arrangement comprises a central steel core 168 clad in a copper layer 167, which is coated in a primary insulator 166 (for example kapton tape (R)) having a high dielectric 20 coefficient, and a secondary insulator 165 which can provide mechanical protection, and a further metal layer, such as a stainless steel layer 169 around the secondary insulator 165. This layer is seam welded and is a snug fit around the insulation 165. The additional stainless steel layer 169 may not always be required, but can be used to provide a second conductive path 25 in the conductor 161, for telemetry or separate power for sensor systems, or a shielding layer to reduce the electrical noise from the power cable. Also, each conductive element could be stranded or further comprised of a plurality of steel conductors each clad with a clad in a copper layer. 10 WO 2011/146949 PCT/ZA2011/000035 By deploying the pump module and motor module separately, the weight of any one module is minimised. Further the pump, and the motor, are both designed to be light weight; typically around 250-500 kg for the motor and connector, and 1000kg for the pump. A permanent magnet design for the 5 motor is particularly suitable for this purpose. By minimising the weight of the pump module, the umbilical can be made thin enough, and therefore flexible enough to pass over sheaf wheels rather than have to be injected into the well using something like a CT injector 10 A modular arrangement also having a separate pump and motor also has benefits in the event of the motor failing; many pump and motor failures are due to electrical faults in the motor. In the present system, the separate removal and replacement of the motor is more convenient than the complete removal of a single combined ESP unit. 15 Referring to figures 8 and 9, the production tubing 4 may be expanded in the region 4a where the motor 67 will be disposed, to allow more room for the pumped fluid to flow past the motor after exiting the pump outlet. A roller expander 80 assembly is attached to the bottom of the motor seal 70, 20 so that there is a torsional link between the motor 67 and the roller expander assembly 80. The roller expanded assembly 80 includes rollers 82 which may be operated to move raidally outwards. The motor 67 and the roller expander assembly 80 are deployed down the production tubing 4. When the roller expander assembly reaches the region where the motor is to be 25 located, the rollers 82 are operated to move radially outwards, causing the inner diameter of the production tubing to expand, typically increasing the radius by 0.25 inches (0.63 cm). The motor 67 then turns the roller expander assembly 80 so that the entire radius of the production tubing 4 is expanded uniformly. The motor and roller expander assembly 80 is set to 11 WO 2011/146949 PCT/ZA2011/000035 its lowest point and pulled up the well during its expansion process. This would be repeated several times to achieved the required tubing expansion. The linkage between the motor 67 then turns the roller expander assembly 80 may be similar to that between the motor and pump shown in figures 4 5 and 5. After a suitable region 4a in the production tubing 4 has been expanded, the rollers 82 are retracted into the roller expander assembly 80, and then the motor 67 and roller expander assembly 80 are raised through the production 10 tubing on the umbilicus 71. The pump module 50 and the motor module 67 may be lowered in separate operations as previously described. This particular method of installing an ESP is ideal for old production wells, where the last remaining oil in place can be extracted, To avoid the expense of a Rig to remove the production tubing 9 and run a expanded section 4a, 15 the in situ expanding method T would obviates the need for the Rig. Detailed description of the embodiments of Figs. 10 - 14 Referring to figures 10 to 12, there is shown a well completion with casing I cemented into the wellbore. A packer 2 is set in the casing which includes 20 a polished bore receptacle (PBR ) 3. The production tubing 4 stings into the PBR with a stinger 5 and seal 6. The production tubing includes other features which enable the electrical powered device to be installed and operated, these will now be described. 25 A no go 7 landing feature is included to provide a reference stop point when installing the first module 50. A locating B profile 8 is included to provide an over pull for module 50, which enables the electrical plug arm 61 to deploy and engage with its matching half 62 mounted in an annular pocket 63. The permanently installed wet connector 62 is supplied with electrical 12 WO 2011/146949 PCT/ZA2011/000035 power via a power cable 9 which penetrates the annular pocket via a bulk head 10. Module 50 consists of a sensor package 64 which measures all motor and 5 well bore parameter, the orientation and plug arm assembly 65, and motor and seal assembly 66, and the lower half of a mating unit 67 described in more detail in figures 13 and 14. The next module to be installed consists of the upper half of the mating unit io 68, a pump inlet 69 and a pump 70, at the upper end of this module is a further mating unit 67. The next module to be installed consists of a further upper mating unit 68, a pump and a upper lock down assembly and seal 71. This keeps all the 15 modules compressed and locked together, while the seal separates the pump inlet from the pump discharge. Referring to figures 13 and 14, this shows the mating unit in more detail, the lower housing body 100 has an internal bore 101, with a sealing surface 20 102 and internal splines 103.On the upper half of the mating unit the outer housing 104 has a reduced diameter 105, and splines 106 at its lowest extreme end which enables it to pass the seal diameter 102 and engage the spines 103 in the lower mating unit body 100. The seal 107 engages the bore 102 and seals the ID from the OD. 25 In the lower mating unit is a shaft 110, mounted in bearings 111 and 112 which transmits torque and thrust. Its upper end is pointed 113 to enable engagement, and splined 114 to transmit the torque to the shaft 120 in the upper mating unit. The internal splines 121 on the upper shaft engage the 13 WO 2011/146949 PCT/ZA2011/000035 spines 114 on the lower shaft. The upper shaft is also mounted in bearings 111 and 112. Internal flow path consisting of drilled holes 130 and 131 enable fluid to 5 pass from the lower side of the mating unit to the upper side of the mating unit when engaged. This enables the pump discharge from the lower pump to enter the pump inlet of the upped pump. In summary, an electric pump assembly is provided in a well, the pump 10 comprising an electric motor module having an first outer housing and a first mating means, an electric pump module having a pump inlet and a pump outlet, and a second outer housing and a second mating means. In one aspect, the electric motor module and electric pump module are capable of being reversibly joined together by the first and second mating means, as 15 the electric motor module includes a first rotating member that is capable of rotating relative to the first outer housing, and the electric pump module includes a second rotating member that is capable of rotating relative to the second outer housing. In this way, the first rotating member and second rotating member can transfer torque when the electric motor module and 20 electric pump module are joined. In another aspect, a flowpath is provided in each module, the flowpaths fluidly communicating when the modules are joined. 14

Claims

1. An electric pump assembly in a well, comprising 5 an electric motor module having an first outer housing and a first mating means an electric pump module having a pump inlet and a pump outlet, a second outer housing and a second mating means 10 the electric motor module and electric pump module capable of being reversibly joined together by the first and second mating means, the electric motor module includes a first rotating member that is capable of 15 rotating relative to the first outer housing, and the electric pump module includes a second rotating member that is capable of rotating relative to the second outer housing, such that the first rotating member and second rotating member can transfer torque when the electric motor module and electric pump module are joined. 20

2. An assembly according to any previous claim wherein the electric motor module is deployed on an electric cable.

3. An assembly according to any previous claim wherein the conductive 25 member or members of the electric cable carries both the weight of itself and the weight of the electric motor module. 15 WO 2011/146949 PCT/ZA2011/000035

4. An assembly according to either claims 2 or 3, wherein the first rotating member and second rotating member are joined by means of interlocking spines.

5 5. An assembly according to any previous claim, wherein there are provided two or more pump modules, and/or two or more electric motor modules.

6. An assembly according to any previous claim, wherein there is also included an tube expansion means that may be releasably attached to and 10 driven by the motor module.

7. An electric motor module according to any previous claim.

8. A pump module according to any of claims 1 to 5. 15

9. An tube expansion module according to claim 5.

10. An electric pump assembly in a well, comprising 20 an electric motor module having an first outer housing and a first mating means an electric pump module having a pump inlet and a pump outlet, a second outer housing and a second mating means 25 the electric motor module and electric pump module capable of being reversibly joined together by the first and second mating means, 16 WO 2011/146949 PCT/ZA2011/000035 the electric motor module including a first flowpath inside the first outer housing, the electric motor module including a second flowpath inside the second outer housing, such that the first and second flowpaths are brought into fluid communication when the electric motor module and electric 5 pump module are joined.

11. An assembly according to claim 10, wherein the electric motor module includes a first rotating member that is capable of rotating relative to the first outer housing, and the electric pump module includes a second rotating 10 member that is capable of rotating relative to the second outer housing, such that the first rotating member and second rotating member can transfer torque when the electric motor module and electric pump module are joined. 15

12. An assembly according to claim 10 or claim 11 wherein electric power is supplied via a supply means situated on a well casing.

13. An assembly according to claim 11 or claim 12, wherein the first rotating member and second rotating member are joined by means of 20 interlocking spines.

14. An assembly according to any of claims 10 - 13, wherein there are provided two or more pump modules, and/or two or more electric motor modules. 25

15. An electric motor module according to any of claims 10 - 14.

16. A pump module according to any of claims 10 - 14. 17