GB2484331A

GB2484331A - Modular electrically driven device in a well

Info

Publication number: GB2484331A
Application number: GB1016910.0A
Authority: GB
Inventors: Philip Head
Original assignee: Artificial Lift Co Ltd
Current assignee: Artificial Lift Co Ltd
Priority date: 2010-10-07
Filing date: 2010-10-07
Publication date: 2012-04-11
Also published as: GB201016910D0

Abstract

An electric pump assembly comprises an electric pump module 50 having a pump inlet 64, pump outlet 67 and mating unit 68 with splines 103 deployed downhole on a retrievable wireline followed by an electric motor module 51 run in on an umbilical 71 such as an electric cable and having mating unit 69 with splines 106 for mating with pump splines 103, and seal 70, motor 67, sensors 61 and umbilical interface 71. Splines 114 on pump shaft 110 engage with internal splines 121 on motor shaft 120 for torque transmission. A roller expander tool (80, fig 8) may be attached to the motor to expand in advance the region of the tubing where the motor is to be located.

Description

MATING UNIT ENABLING THE DEPLOYMENT OF A MODULAR

ELECTRICALLY DRIVEN DEVICE IN A WELL

FIELD OF THE INVENTION

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.

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 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 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 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. WO98 122692 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 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 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 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 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 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 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 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 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 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.

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 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 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 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 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 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 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 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 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 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 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 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 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 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

S

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 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.

BRIEF DESCRIPTION OF THE DRAWINGS

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; Fig. 5 shows a side view of a module mating unit, uncoupled; Fig. 6 shows a cross sectional view of the electric cable; 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 production tubing.

DETAILED DESCRIPTION

Referring to figures 1 to 3, there is shown a well completion with casing 1 cemented into the wellbore. A packer 2 with clastomer 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 S and seal 6.

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.

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 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 S. When the surface operator detects that the pump has reached this point (for example by monitoring the weight 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 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 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.

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 splines 106 at its lowest 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 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 splines 121 on the upper shaft engage the 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 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 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 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 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 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 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 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.

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 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 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.

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, 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 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 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 may be similar to that between the motor and pump shown in figures 4 and 5.

After a suitable region 4a in the production tubing 4 has been expanded, the rollers 82 are refracted into the roller expander assembly 80, and then the motor 67 and roller expander assembly 80 are raised through the production 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, the in situ expanding method T would obviates the need for the Rig.

Claims

Claims 1. 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 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 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.
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 member or members of the electric cable carries both the weight of itself and the weight of the electric motor module.
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 splines.
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 rcleasably attached to and 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.
9. An tube expansion module according to claim 5.