CABLE INJECTOR FOR DEPLOYING ARTIFICIAL LIFT SYSTEM

Abstract

An injector for deploying a cable into a wellbore includes a traction assembly having at least a stationary segment and a movable segment. Each segment includes: a drive sprocket; an idler sprocket; a track looped around and between the sprockets; a set of grippers fastened to and disposed along the respective track, and a frame. The frame: is connected to the stationary segment, has a coupling for connection to a pressure control assembly (PCA), and has a passage for receiving the cable. The injector further includes a motor torsionally connected to the drive sprocket of the stationary segment.

Description

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

Embodiments of the present disclosure generally relate to a cable injector for deploying an artificial lift system.

2. Description of the Related Art

The oil industry has utilized electric submersible pumps (ESPs) to produce high flow-rate wells for decades, the materials and design of these pumps has increased the ability of the system to survive for longer periods of time without intervention. These systems are typically deployed on the tubing string with the power cable fastened to the tubing by mechanical devices such as metal bands or metal cable protectors. Well intervention to replace the equipment requires the operator to pull the tubing string and power cable requiring a well servicing rig and special spooler to spool the cable safely. The industry has tried to find viable alternatives to this deployment method especially in offshore and remote locations where the cost increases significantly. There has been limited deployment of cable inserted in coil tubing where the coiled tubing is utilized to support the weight of the equipment and cable. Although this system is seen as an improvement over jointed tubing, the cost, reliability and availability of coiled tubing units have prohibited use on a broader basis.

SUMMARY OF THE DISCLOSURE

Embodiments of the present disclosure generally relate to a cable injector for deploying an artificial lift system. In one embodiment, an injector for deploying a cable into a wellbore includes a traction assembly having at least a stationary segment and a movable segment. Each segment includes: a drive sprocket; an idler sprocket; a track looped around and between the sprockets; a set of grippers fastened to and disposed along the respective track, and a frame. The frame: is connected to the stationary segment, has a coupling for connection to a pressure control assembly (PCA), and has a passage for receiving the cable. The injector further includes a motor torsionally connected to the drive sprocket of the stationary segment.

In another embodiment, a method of deploying a downhole tool into a wellbore includes: connecting the downhole tool to a cable; lowering the downhole tool into a pressure control assembly (PCA) and wellhead adjacent to the wellbore using the cable; after lowering the downhole tool, connecting a cable injector to the PCA and closing the cable injector around the cable; and operating the cable injector, thereby injecting the cable into the wellbore and lowering the downhole tool to a deployment depth in the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.

FIG. 1A illustrates a launch and recovery system (LARS) at a wellsite for deploying an artificial lift system (ALS), according to one embodiment of the present disclosure. FIG. 1B illustrates a power cable of the ALS. FIGS. 1C and 1D illustrate a wireline of the ALS.

FIGS. 2A-2D illustrate an electric submersible pump (ESP) of the ALS.

FIGS. 3A, 3C, and 3D illustrate a cable injector of the LARS in an open or partially open position. FIG. 3B illustrates the cable injector in a closed position.

FIGS. 4A and 4B illustrate insertion of the ESP into a wellbore using the LARS. FIG. 4C illustrates operation of the ESP.

FIG. 5A illustrates a lubricator and the cable injector connected thereto for use with the LARS, according to another embodiment of the present disclosure. FIG. 5B illustrates an alternative pressure control assembly (PCA) for use with the LARS, according to another embodiment of the present disclosure.

FIG. 6A illustrates a power cable deployed ESP for use with a modified LARS. FIG. 6B illustrates insertion of the power cable deployed ESP into the wellbore using the cable injector, according to another embodiment of the present disclosure. FIG. 6C illustrates operation of the power cable deployed ESP.

FIGS. 7A-7D illustrate insertion of the power cable deployed ESP into the wellbore using the cable injector, according to another embodiment of the present disclosure. FIG. 7E illustrates operation of the power cable deployed ESP.

FIG. 8A illustrates an alternative cable injector for the LARS. FIG. 8B illustrates a portion of another alternative cable injector for the LARS.

DETAILED DESCRIPTION

FIG. 1A illustrates a launch and recovery system (LARS) 1 at a wellsite for deploying an artificial lift system (ALS), according to one embodiment of the present disclosure. The LARS 1 may include a wireleine truck 40, a pressure control assembly (PCA), such as one or more (two shown) blowout preventers (BOPs) 38, one or more running tools 59 (FIG. 4A), and a cable injector 100 (FIG. 3A).

A wellbore 5w has been drilled from a surface 5s of the earth into a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir 6 (FIG. 4A). A string of casing 10c has been run into the wellbore 5w and set therein with cement (not shown). The casing 10c has been perforated 9 (FIG. 4B) to provide to provide fluid communication between the reservoir 6 and a bore of the casing 10c. A wellhead 10h has been mounted on an end of the casing string 10c. A string of production tubing 10p extends from the wellhead 10h to the reservoir 6 to transport production fluid 7 (FIG. 4C) from the reservoir 6 to the surface 5s. A packer 8 (FIG. 4A) has been set between the production tubing 10p and the casing 10c to isolate an annulus 10a (FIG. 4B) formed between the production tubing and the casing from production fluid 7.

A production (aka Christmas) tree 30 has been installed on the wellhead 10h. The production tree 30 may include a master valve 31, tee 32, a swab valve 33, a cap 34 (FIG. 4C), and a production choke 35. Production fluid 7 from the reservoir 6 may enter a bore of the production tubing 10p, travel through the tubing bore to the surface 5s. The production fluid 7 may continue through the master valve 31, the tee 32, and through the choke 35 to a flow line (not shown). The production fluid 7 may continue through the flow line to a separation, treatment, and storage facility (not shown). The reservoir 6 may initially be naturally producing and may deplete over time to require an artificial lift system (ALS) to maintain production. The ALS may include a control unit 39 (FIG. 4C) located at the surface 5s, a power cable 20, and a downhole assembly, such as an electrical submersible pump (ESP) 60 (FIGS. 2A-2D). Alternatively, the downhole assembly may include an electrical submersible compressor. In anticipation of depletion, the production tubing string 10p may have been installed with a dock 15 (FIG. 4A) assembled as a part thereof and the power cable 20 secured therealong.

The dock 15 may receive a lander 65 (FIG. 2A) of the ESP 60 and include a subsurface safety valve (SSV) 3, one or more sensors 4u,b, a part, such as one or more followers 13, of an auto-orienter, a penetrator 14, a part, such as one or more boxes 16, of a wet matable connector, a polished bore receptacle (PBR) 17, and a torque profile. The SSV 3 may include a housing, a valve member, a biasing member, and an actuator. The valve member may be a flapper operable between an open position and a closed position. The flapper may allow flow through the housing/production tubing bore in the open position and seal the housing/production tubing bore in the closed position. The flapper may operate as a check valve in the closed position i.e., preventing flow from the reservoir 6 to the wellhead 10h but allowing flow from the wellhead to the reservoir. Alternatively, the SSV 3 may be bidirectional. The actuator may be hydraulic and include a flow tube for engaging the flapper and forcing the flapper to the open position. The flow tube may also be a piston in communication with a hydraulic conduit of a control line 11 extending along an outer surface of the production tubing 10p to the wellhead 10h. Injection of hydraulic fluid into the hydraulic conduit may move the flow tube against the biasing member (i.e., spring), thereby opening the flapper. The SSV 3 may also include a spring biasing the flapper toward the closed position. Relief of hydraulic pressure from the conduit may allow the springs to close the flapper.

Each sensor 4u,b may be a pressure or pressure and temperature (PT) sensor. The sensors 4u,b may be located along the production tubing 10p so that the upper sensor 4u is in fluid communication with an outlet of the ESP 60 and a lower sensor 4b is in fluid communication with an inlet 80 (FIG. 2C) of the ESP 60. The sensors 4u,b may be in data communication with a motor controller (not shown) of the control unit 39 via a data conduit of the control line 11, such as an electrical or optical cable. The data conduit may also provide power for the sensors 4u,b.

The penetrator 14 may receive an end of the cable 20. The cable 20 may be fastened along an outer surface of the production tubing 10p at regular intervals, such as by clamps or bands (not shown). The wet matable connector 16, 66 may include a pair of pins 66 (FIG. 2A) and boxes 16 for each conductor 21 (FIG. 1B, three shown) of the cable 20. A suitable wet matable connector is discussed and illustrated U.S. Pat. Pub. No. 2011/0024104, which is herein incorporated by reference in its entirety.

The auto-orienter 13, 69 may include a cam 69 (FIG. 2A) and one or more followers 13. As the ESP 60 is lowered into the dock 15, the auto-orienter 13, 69 may rotate the ESP to align the pins 66 with the respective boxes 13. Each of the lander 65 and dock 15 may further include a torque profile, such one or more splines 67 (FIG. 2A), 18. Engagement of the splines 67, 18 may torsionally connect the ESP 60 to the production tubing 10p. A landing shoulder may be formed at a top of each of the splines 18 to longitudinally support the ESP 60 in the production tubing 10p.

The reservoir 6 may be live and shut-in by the closed master valve 31, swab valve 33, and SSV 3. Alternatively, the reservoir 6 may be dead due to depletion and/or by kill fluid. Alternatively, the LARS 1 may further include a lubricator 200 (FIG. 5A) for deploying the ESP 60. Alternatively, if the dock 15, power cable 20, and control line 11 was not installed with the production tubing 10p, a workover rig (not shown) may be used to remove the production tubing, install the dock, power cable, and control line, and reinstall the production tubing. The LARS 1 may then not be needed for the initial installation of the ESP 60 but may be used for later servicing of the ESP.

The wireline truck 40 may be deployed to the wellsite. One or more delivery trucks (not shown) may transport the BOPs 38, ESP 60, and running tool 59 to the wellsite. The wireline truck 40 may be used to remove the cap 34 from the tree 30 and install the BOPs 38 onto the tree. The wireline truck 40 may include a control room 42, a generator (not shown), a frame 44, a power converter 45, a winch 47 having a deployment cable, such as wireline 50, wrapped therearound, and a boom 48. Alternatively, the deployment cable may be slickline or wire rope. The control room 42 may include a control console 42c and a programmable logic controller (PLC) 42p. The generator may be diesel-powered and may supply a one or more phase (i.e., three) alternating current (AC) power signal to the power converter 45. Alternatively, the generator may produce a direct current (DC) power signal. The power converter 45 may include a one or more (i.e., three) phase transformer for stepping the voltage of the AC power signal supplied by the generator from a low voltage signal to an ultra low voltage signal. The power converter 45 may further include a one or more (i.e., three) phase rectifier for converting the ultra low voltage AC signal supplied by the transformer to an ultra low voltage direct current (DC) power signal. The rectifier may supply the ultra low voltage DC power signal to the wireline 50 for transmission to the running tool 59.

The rectifier may be in electrical communication with the wireline 50 via an electrical coupling (not shown), such as brushes or slip rings, to allow power and data transmission through the wireline while the winch 47 winds and unwinds the wireline. The control console 42c may include one or more input devices, such as a keyboard and mouse or trackpad, and one or more video monitors. Alternatively, a touchscreen may be used instead of the monitor and input devices.

The boom 48 may be an A-frame pivoted to the frame 44 and the wireline truck 40 may further include a boom hoist (not shown) having a pair of piston and cylinder assemblies. Each piston and cylinder assembly may be pivoted to each beam of the boom and a respective column of the frame. The wireline truck 40 may further include a hydraulic power unit (HPU) 46. The HPU 46 may include a hydraulic fluid reservoir, a hydraulic pump, an accumulator, and one or more control valves for selectively providing fluid communication between the reservoir, the accumulator, and the piston and cylinder assemblies. The hydraulic pump may be driven by an electric motor. The winch 47 may include a drum having the wireline 50 wrapped therearound and a motor for rotating the drum to wind and unwind the wireline. The winch motor may be electric or hydraulic. A sheave may hang from the boom 48. The wireline 50 may extend through the sheave and an end of the wireline may be fastened to a cablehead of the running tool 59. The HPU 46 may also be connected to the BOPs 38.

The BOPs 38 may include a housing having a connector, such as a flange, formed at each longitudinal end thereof. A lower of the BOP flanges may be connected to an upper flange of the swab valve 33 by fasteners (not shown), such as bolts or studs and nuts. The BOPs housing may have a bore therethrough corresponding to a bore of the production tubing 10p. The BOPs 38 may include one or more ram preventers, such as a blind ram preventer and a cable ram preventer. The blind ram preventer may be capable of cutting the wireline 50 when actuated and sealing the bore. The cable preventer may be capable of sealing against an outer surface of the wireline 50 when actuated.

FIG. 1B illustrates the power cable 20. The cable 20 may include a core 27 having one or more (three shown) wires 25 and a jacket 26, and one or more layers 29i,o of armor. Each wire 25 may include a conductor 21, a jacket 22, a sheath 23, and bedding 24. The conductors 21 may each be made from an electrically conductive material, such as aluminum, copper, or alloys thereof. The conductors 21 may each be solid or stranded. Each jacket 22 may electrically isolate a respective conductor 21 and be made from a dielectric material, such as a polymer (i.e., ethylene propylene diene monomer (EPDM)). Each sheath 23 may be made from lubricative material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape helically wound around a respective wire jacket 22. Each bedding 24 may serve to protect and retain the respective sheath 23 during manufacture and may be made from a polymer, such as nylon. The core jacket 26 may protect and bind the wires 25 and be made from a polymer, such as EPDM or nitrile rubber.

The armor 29i,o may be made from one or more layers 29i,o of high strength material (i.e., tensile strength greater than or equal to one hundred, one fifty, or two hundred kpsi). The high strength material may be a metal or alloy and corrosion resistant, such as galvanized steel, aluminum, or a polymer, such as a para-aramid fiber. The armor 29i,o may include two contra-helically wound layers 29i,o of wire, fiber, or strip. Additionally, a buffer (not shown) may be disposed between the armor layers 29i,o. The buffer may be tape and may be made from the lubricative material. Additionally, the cable 20 may further include a pressure containment layer 28 made from a material having sufficient strength to contain radial thermal expansion of the core 27 and wound to allow longitudinal expansion thereof. Alternatively, the power cable 20 may be flat.

FIGS. 1C and 1D illustrate the wireline 50. The wireline 50 may include an inner core 51, an inner jacket 52, a shield 53, an outer jacket 56, and one or more layers 57i,o of armor. The inner core 51 may be the first conductor and made from an electrically conductive material, such as aluminum, copper, or alloys thereof. The inner core 51 may be solid or stranded. The inner jacket 52 may electrically isolate the core 51 from the shield 53 and be made from a dielectric material, such as a polymer (i.e., polyethylene). The shield 53 may serve as the second conductor and be made from the electrically conductive material. The shield 53 may be tubular, braided, or a foil covered by a braid. The outer jacket 56 may electrically isolate the shield 53 from the armor 57i,o and be made from a fluid-resistant dielectric material, such as polyethylene or polyurethane. The armor 57i,o may be made from one or more layers 57i,o of the high strength material to support the ESP 60. The armor 57i,o may include two contra-helically wound layers 57i,o of wire, fiber, or strip.

Additionally, the wireline 50 may include a sheath 55 disposed between the shield 53 and the outer jacket 56. The sheath 55 may be made from lubricative material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape helically wound around the shield 53. If lead is used for the sheath 55, a layer of bedding 54 may insulate the shield 53 from the sheath and be made from the dielectric material. Additionally, a buffer 58 may be disposed between the armor layers 57i,o. The buffer 58 may be tape and may be made from the lubricative material.

FIGS. 2A-2D illustrate the ESP 60. The ESP 60 may include the lander 65, an electric motor 70, a shaft seal 75, the inlet 80, a pump having one or more sections 85, 95, and a packoff 99. Housings 70h-95h of each of the ESP components may be longitudinally and torsionally connected, such as by flanged connections 61, 90u,b. Alternatively, the flanged connections 90u,b may be replaced by the flanged connections 61. Shafts 70s-95s of the motor 70, shaft seal 75, inlet 80, and pump sections 85, 95 may be torsionally connected, such as by shaft couplings 63. Alternatively, the housings 70h-95h may be connected by threaded connections.

The motor 70 may be filled with a dielectric, thermally conductive liquid lubricant, such as motor oil. The motor 70 may be cooled by thermal communication with the production fluid 7. The motor 70 may include a thrust bearing (not shown) for supporting the drive shaft 70s. In operation, the motor 70 may rotate the drive shaft 70s, thereby driving the pump shafts 85s, 95s of the pump 85, 95. The drive shaft 70s may be directly drive the pump shaft 85s, 95s (no gearbox).

The motor 70 may be an induction motor, a switched reluctance motor (SRM) or a permanent magnet motor, such as a brushless DC motor (BLDC). Additionally, the ESP 60 may include a second (or more) motor for tandem operation with the motor 70. The induction motor may be a two-pole, three-phase, squirrel-cage induction type and may run at a nominal speed of thirty-five hundred rpm at sixty Hz. The SRM motor may include a multi-lobed rotor made from a magnetic material and a multi-lobed stator. Each lobe of the stator may be wound and opposing lobes may be connected in series to define each phase. For example, the SRM motor may be three-phase (six stator lobes) and include a four-lobed rotor. The BLDC motor may be two pole and three phase. The BLDC motor may include the stator having the three phase winding, a permanent magnet rotor, and a rotor position sensor. The permanent magnet rotor may be made of one or more rare earth, ceramic, or ceramic-metallic composite (aka cermet) magnets. The rotor position sensor may be a Hall-effect sensor, a rotary encoder, or sensorless (i.e., measurement of back EMF in undriven coils by the motor controller).

The shaft seal 75 may isolate the reservoir fluid 7 being pumped through the pump 85, 95 from the lubricant in the motor 70 by equalizing the lubricant pressure with the pressure of the reservoir fluid 7. The shaft seal 75 may house a thrust bearing (not shown) capable of supporting thrust load from the pump 85, 95. The shaft seal 75 may be positive type or labyrinth type. The positive type may include an elastic, fluid-barrier bag to allow for thermal expansion of the motor lubricant during operation. The labyrinth type may include tube paths extending between a lubricant chamber and a reservoir fluid chamber providing limited fluid communication between the chambers.

The pump inlet 80 may be standard type, static gas separator type, or rotary gas separator type depending on the gas to oil ratio (GOR) of the production fluid 7. The standard type inlet may include a plurality of ports 81 allowing reservoir fluid 7 to enter a lower or first section 85 of the pump 85, 95. The standard inlet may include a screen (not shown) to filter particulates from the reservoir fluid 7. The static gas separator type may include a reverse-flow path to separate a gas portion of the reservoir fluid 7 from a liquid portion of the reservoir fluid.

The packoff 99 may have one or more fixed seals received by the polished bore receptacle 17 of the dock 15, thereby isolating discharge ports (not shown) of the packoff 99 from the pump inlet 80. The packoff 99 may further include a latch (not shown) operable to engage a latch profile (not shown) of the dock 15, thereby longitudinally connecting the ESP 60 to the production tubing 10p. The packoff 99 may further include an inner profile for engagement with the running tool 59. Additionally, the packoff 99 may include a bypass vent (not shown) for releasing gas separated by the pump inlet 80 that may collect below the packoff and preventing gas lock of the pump 85, 95. A pressure relief valve (not shown) may be disposed in the bypass vent.

The pump 85, 95 may be centrifugal or positive displacement. The centrifugal pump may be a radial flow or mixed axial/radial flow. The positive displacement pump may be progressive cavity. Each section 85, 95 of the centrifugal pump may include one or more stages, each stage having an impeller and a diffuser. The impeller may be torsionally and longitudinally connected to the respective pump shaft 85s, 95s, such as by a key. The diffuser may be longitudinally and torsionally connected to a housing of the pump, such as by compression between a head and base screwed into the housing. Rotation of the impeller may impart velocity to the reservoir fluid 7 and flow through the stationary diffuser may convert a portion of the velocity into pressure. The pump 85, 95 may deliver the pressurized reservoir fluid 7 to the packoff bore.

Alternatively, the pump 85, 95 may include one or more sections of a high speed compact pump discussed and illustrated at FIGS. 1C and 1D of U.S. patent application Ser. No. 12/794,547, filed Jun. 4, 2010, which is herein incorporated by reference in its entirety. High speed may be greater than or equal to ten thousand, fifteen thousand, or twenty thousand revolutions per minute (RPM). Each compact pump section may include one or more stages, such as three. Each stage may include a housing, a mandrel, and an annular passage formed between the housing and the mandrel. The mandrel may be disposed in the housing. The mandrel may include a rotor, one or more helicoidal rotor vanes, a diffuser, and one or more diffuser vanes. The rotor may include a shaft portion and an impeller portion. The rotor may be supported from the diffuser for rotation relative to the diffuser and the housing by a hydrodynamic radial bearing formed between an inner surface of the diffuser and an outer surface of the shaft portion. The rotor vanes may interweave to form a pumping cavity therebetween. A pitch of the pumping cavity may increase from an inlet of the stage to an outlet of the stage. The rotor may be longitudinally and torsionally connected to the motor drive shaft and be rotated by operation of the motor. As the rotor is rotated, the production fluid 7 may be pumped along the cavity from the inlet toward the outlet. The annular passage may have a nozzle portion, a throat portion, and a diffuser portion from the inlet to the outlet of each stage, thereby forming a Venturi.

Additionally, the ESP 60 may further include a sensor sub (not shown). The sensor sub may be employed in addition to or instead of the sensors 4u,b. The sensor sub may include a controller, a modem, a diplexer, and one or more sensors (not shown) distributed throughout the ESP 60. The controller may transmit data from the sensors to the motor controller via conductors 21 of the cable 20. Alternatively, the cable 20 may further include a data conduit, such as data wires or optical fiber, for transmitting the data. A PT sensor may be in fluid communication with the reservoir fluid 7 entering the pump inlet 80. A GOR sensor may also be in fluid communication with the reservoir fluid 7 entering the pump inlet 80. A second PT sensor may be in fluid communication with the reservoir fluid 7 discharged from the pump outlet/ports. A temperature sensor (or PT sensor) may be in fluid communication with the lubricant to ensure that the motor 70 is being sufficiently cooled. A voltage meter and current (VAMP) sensor may be in electrical communication with the cable 20 to monitor power loss from the cable. Further, one or more vibration sensors may monitor operation of the motor 70, the pump 85, 95, and/or the shaft seal 75. A flow meter may be in fluid communication with the pump outlet for monitoring a flow rate of the pump 85, 95. Alternatively, the tree 30 may include a flow meter (not shown) for measuring a flow rate of the pump 85, 95 and the tree flow meter may be in data communication with the motor controller.

The control unit 39 may include a power source, such as a generator or transmission lines, and a motor controller for receiving an input power signal from the power source and outputting a power signal to the motor 70 via the power cable and the connector 105. For the induction motor, the motor controller may be a switchboard (i.e., logic circuit) for simple control of the motor 70 at a nominal speed or a variable speed drive (VSD) for complex control of the motor. The VSD controller may include a microprocessor for varying the motor speed to achieve an optimum for the given conditions. The VSD may also gradually or soft start the motor, thereby reducing start-up strain on the shaft and the power supply and minimizing impact of adverse well conditions.

For the SRM or BLDC motors, the motor controller may sequentially switch phases of the motor, thereby supplying an output signal to drive the phases of the motor 70. The output signal may be stepped, trapezoidal, or sinusoidal. The BLDC motor controller may be in communication with the rotor position sensor and include a bank of transistors or thyristors and a chopper drive for complex control (i.e., variable speed drive and/or soft start capability). The SRM motor controller may include a logic circuit for simple control (i.e. predetermined speed) or a microprocessor for complex control (i.e., variable speed drive and/or soft start capability). The SRM motor controller may use one or two-phase excitation, be unipolar or bi-polar, and control the speed of the motor by controlling the switching frequency. The SRM motor controller may include an asymmetric bridge or half-bridge.

FIGS. 3A, 3C, and 3D illustrate the cable injector 100 in an open or partially open position. FIG. 3B illustrates the cable injector 100 in a closed position. The cable injector 100 may include a traction assembly 101, a drive motor 102, and a frame 103. The traction assembly 101 may include one or more segments, such as a stationary segment 101d and a movable segment 101p. The stationary segment 101d may be connected to a base 103b of the frame 103, such as by one or more fasteners (not shown). The frame 103 may further include a coupling, such as a flange 103f, connected to the base 103b, such as by one or more fasteners or a weld. The flange 103f may mate with a corresponding upper flange of the BOPs 38 and be connected thereto by one or more fasteners. Alternatively, the coupling may be threaded or quick-connect. The frame 103 may further have a passage, such a slit 115 formed through walls of the flange 103f and base 103b for receiving the wireline 50.

Each segment 101d,p may include a respective: body 105d,p, conveyor 106d,p, tensioner 107p (stationary tensioner not shown), and counter bearing 116d,p. Each body 105d,p may be rectangular and have a cavity formed therein. Each body 105d,p may have an open inner face for operation of the respective conveyor 106d,p and open upper and lower ends for assembly thereof. The upper and lower ends may be closed with end caps (not shown). Each body 105d,p may have a respective coupling, such as a hinge knuckle 117p,d, formed at each inner end thereof. The movable segment 101p may initially be connected to the stationary segment 101d, such as pivoted, by meshing a first mating pair of the knuckles 117p,d and inserting a hinge pin 104a through the meshed first pair such that the movable segment may swing between the open and closed positions. The movable segment 101p may then be closed by meshing a second mating pair of the knuckles 117p,d and inserting a latch pin 104b through the meshed second pair. The open position may be utilized for receiving the wireline 50 and the closed position may be utilized for lowering and/or driving the wireline into the wellbore 5w.

Each conveyor 106d,p may include a respective: track, such as a belt 108d,p, gear 109d,p, idler sprocket 110d,p, drive sprocket 111d,p, idler hub (not shown), drive hub 112d,p, and set 113d,p of grippers 113. Alternatively, the tracks may be roller chains. Each gripper 113 may be fastened to the respective belt 108d,p, such as by one or more fasteners (not shown) extending through respective holes (not shown) formed through the belt. Each hole may be counter bored or counter sunk such that the fastener head is flush or sub-flush with an underside of the belt. Each set 113d,p may include grippers 113 spaced along an outside of the respective belt 108d,p at regular intervals. Each gripper 113 may be made from an abrasion resistant material, such as a metal, alloy, or cermet. Each gripper 313 may have an upper portion, a mid portion, and a lower portion. The mid portion of each gripper 113 may have a central recess for receiving the wireline 50 and wings extending transversely from the recess. The wings may form a bearing surface for mating with wings of an opposed gripper during operation of the cable injector 100. The upper and lower portions of each gripper 113 may taper toward the belt going away from the mid portion. A nominal width of each recess may correspond to a diameter of the wireline 50.

Each set 113d,p of grippers 113 may engage a fraction of an outer surface of the wireline 50. In the illustrated case of two sets 113d,p, each set may engage one-half of the wireline outer surface. Alternatively, the traction assembly 101 may include a second (or more) movable segment, such as a stationary segment and two moveable segments (FIG. 8B) or a stationary segment and three moveable segments. In the alternative having two movable segments, each set of grippers may engage one-third of the wireline outer surface and in the alternative having three movable segments, each set may engage one-fourth of the wireline outer surface.

Teeth may be formed in the recess for gripping the wireline 50. Alternatively, a die having the teeth may be fastened to the gripper 113. The teeth may be circumferential and decrease the nominal width of the recess to be less than the wireline diameter such that the teeth may penetrate the outer armor 57o. A receiver opening may also be formed through each central portion for receiving a cog 114p,d of the respective sprockets 110p,d, 111p,d. A corresponding passage may be formed through the belt adjacent each receiver opening for passage of the cog 114p,d therethrough. A length of each gripper and the interval between adjacent grippers may correspond to a pitch of the respective sprockets 110p,d, 111p,d. Each receiver opening may be shaped to mesh with the cog 114p,d such that the gripper 113 (and belt) seats onto the adjacent bottom lands of the sprocket 110p,d, 111p,d, thereby transmitting driving torque/force directly from the cog to the gripper 113. The gripper 113 may then transmit the driving force to the respective belt 108d,p via the fasteners.

Each belt 108d,p may be endless and loop around and between the respective sprockets 110p,d, 111p,d. Each belt 108d,p may have a flat or trapezoidal cross-section. Each belt 108d,p may include an inner carcass made from one or more plies bonded together using an adhesive and an outer cover encapsulating the carcass. The plies may each be made from natural or synthetic fibers, such as polymer, metal/alloy, ceramic, or carbon. The cover may be made from a flexible material, such as an elastomer, thermoplastic elastomer, or other suitable polymer. Each belt 108d,p may have a length sufficient to distribute clamping force along the wireline 50 such that a clamping pressure does not crush the wireline. The gripper teeth and belt length may also be configured such that the teeth do not damage the outer armor layer 57o.

Each hub 112d,p may be mounted to the respective body 105d,p by bearings (not shown) such that the hub may rotate relative to the body while being longitudinally and transversely supported by the body. Each sprocket 110p,d, 111p,d may be disposed on a respective hub 112d,p and torsionally connected thereto, such as by interference fit or fastener. Each gear 109d,p may be disposed on a respective drive hub 112d,p and torsionally connected thereto, such as by interference fit or fastener. The stationary drive hub 112d may also have a shaft coupling (not shown) for receiving a shaft coupling (not shown) of a drive shaft 102d of the motor 102, thereby torsionally connecting the drive hub to the drive shaft. The gears 109d,p may be configured to mesh upon closing of the cable injector 100, thereby torsionally connecting the stationary drive hub 112d to the movable drive hub 112p.

The drive motor 102 may be hydraulic and bidirectional such that the cable injector 100 may be used to push the wireline 50 into the wellbore 5w and pull the wireline from the wellbore. The drive motor 102 may have a housing 102h connected to a bracket 103t of the frame 103, such as by one or more fasteners (not shown). An inlet and outlet of the drive motor may be in fluid communication with the HPU 46 via flexible conduits, such as hoses 41a,b. The drive motor 102 may further include a rotor (not shown) mounted in the housing for rotation relative thereto by one or more bearings (not shown). Injection of hydraulic fluid, such as oil, into the inlet may torsionally drive the rotor relative to the housing 102h. The rotor may be torsionally connected to the drive shaft 102d. The drive motor 102 may further include a motor lock operable between a locked position and an unlocked position. The motor lock may include a clutch torsionally connecting the rotor and the housing 102h in the locked position and disengaging the rotor from the housing in the unlocked position. The clutch may be biased toward the locked position and further include an actuator, such as a piston, operable to move the clutch to the unlocked position in response to hydraulic fluid being supplied to the motor. Alternatively the motor 102 may have an additional hydraulic port for supplying the actuator. Alternatively, the motor 102 may be electric or pneumatic.

Each tensioner 107p may include a piston and cylinder assembly and a roller. Each piston and cylinder assembly may have a first end connected to the respective body and a second end mounted to the roller for rotation of the roller relative thereto. Each tensioner 107p may be in fluid communication with the HPU 46 via a flexible conduit, such as a hose 43 (common or individual). Each tensioner 107p may be operated to extend the roller into engagement with the respective belt 108d,p, thereby tightening the respective belt 108d,p and gripper set 113d,p into engagement with the respective sprockets 110p,d, 111p,d. Each counter bearing 116p may include a base connected to the respective body 105d,p and one or more rollers mounted along the base for rotation relative thereto. As each tensioner 107p tightens the respective belt 108d,p, the belt may also be tightened into engagement with the respective counter bearing rollers, thereby supporting the belt and keeping the belt from bowing inwardly.

Referring to FIG. 8A, alternatively, the movable segment may be mounted on a linear actuator, such as a piston and cylinder assembly, such that the movable segment may be radially moved toward and away from the stationary segment. This alternative facilitates adjusting of the clamping force against an outer surface of the wireline and may accommodate radial contraction of the wireline in response to tension exerted on the wireline.

Alternatively, each belt may include segments spaced apart to form the cog passage instead of being continuous and the grippers may link the belt segments. Alternatively, the cable injector 100 may be used with other types of cable, such as slickline or wire rope. Alternatively, the cable injector 100 may be configured to inject a workstring, such as coiled tubing or continuous sucker rod.

FIGS. 4A and 4B illustrate insertion of the ESP 60 into the wellbore 5w using the LARS 1. FIG. 4C illustrates operation of the ESP 60. Referring specifically to FIG. 4A, the tree valves 31, 33 may be opened. The ESP 60 and running tool 59 may be assembled, lowered, and suspended in the tree 30, wellhead 10h, and/or upper portion of the wellbore 5w by the winch 47. The running tool 59 may include an electrically operated gripper for connecting to the packoff 99.

The cable injector 100 may then be connected to the BOPs 38. The cable injector 100 may be connected with the movable segment 101p in the open position or without the movable segment. If connected without the movable segment 101p, the movable segment 101p may then be connected to the stationary segment 101d in the open position. The movable segment 101p may then be closed and secured around the wireline 50. The hoses 41a,b and 43 may then be connected to the cable injector 100. The tensioners 107p may then be operated to engage the respective belts 108d,p with the sprockets 110d,p, 111d,p. The winch 47 may be idled and the drive motor 102 may then be operated to lower the ESP 60 into the wellbore 5w using the wireline 50 until the lander 65 is proximate the dock follower 13. Should lowering of the ESP 60 become obstructed, such as by deviations in the production tubing 10p, the cable injector 100 may push the wireline 50 into the wellbore 5w.

Alternatively, the body 105d may have a second coupling, such as a flange, connected at an end opposite the base such that a second cable injector may be connected thereto and the cable injectors operated in tandem.

Referring specifically to FIG. 4B, the ESP 60 may be slowly lowered while the follower 13 engages the cam 69 and rotates the ESP 60 relative to the production tubing 10p to align the wet-matable connector 16, 66. Referring specifically to FIG. 4C, lowering of the ESP 60 may continue to engage the wet-matable connector 16, 66 and to engage the packoff seal with the PBR 17. The packoff latch may be set. The running tool gripper may be operated using the wireline 50 to release the ESP 60 from the running tool 59. Operation of the cable injector 100 may then be reversed to retrieve the wireline 50 and running tool 59 from the wellbore 5w. The cable injector 100, running tool 59, and BOPs 38 may be removed from the production tree 30. The cap 34 may be connected to the production tree 30. The SSV 3 may be opened and the ESP 60 operated to pump production fluid 7 from the wellbore 5w. Retrieval of the ESP 60 for service or replacement may be accomplished by reversing the insertion method.

FIG. 5A illustrates a lubricator 200 and the cable injector 100 connected thereto for use with the LARS 1, according to another embodiment of the present disclosure. The lubricator 200 may include a tool housing 205 (aka lubricator riser), a seal head 210, a tee 215, and a shutoff valve 220. The lubricator components may be connected, such as by flanged connections. The tee 215 may also have a lower flange for connecting to the upper BOP flange. The cable injector 100 may connect to an upper flange of the seal head 210. The seal head 210 may include one or more stuffing boxes 225u,b and a grease injector 230. Each stuffing box 225u,b may include a packing, a piston, and a housing. A port may be formed through each stuffing box housing in communication with the piston. The port may be connected to the HPU 46 via a hydraulic conduit (not shown). When operated by hydraulic fluid, the piston may longitudinally compress the packing, thereby radially expanding the packing inward into engagement with the wireline 50. Each stuffing box may further include a spring for returning the piston or the resiliency of the packing may be sufficient.

The grease injector may include a housing integral with each stuffing box housing and one or more seal tubes. Each seal tube may have an inner diameter slightly larger than an outer diameter of the wireline 50, thereby serving as a controlled gap seal. An inlet port and an outlet port may be formed through the grease injector/stuffing box housing. A grease conduit (not shown) may connect an outlet of a grease pump (not shown) with the inlet port and another grease conduit (not shown) may connect the outlet port with a grease reservoir (not shown). Alternatively, the outlet port may discharge into a spent fluid container. Grease 330 (FIG. 6C) may be injected from the grease pump into the inlet port and along the slight clearance formed between the seal tube and the wireline 50 to lubricate the wireline, reduce pressure load on the stuffing box packings, and increase service life of the stuffing box packings.

FIG. 5B illustrates an alternative PCA 240 for use with the LARS 1, according to another embodiment of the present disclosure. A more detailed discussion regarding use of the lubricator 200 and PCA 240 may be found in U.S. Prov. App. No. 61/550,537 (Atty. Dock. No. ZEIT/0012USL), which is herein incorporated by reference in its entirety. The PCA 240 may include one or more clamps 241u,b, a driver 250, one or more blow out preventers (BOPs) 38, 265 and a shutoff valve 262. Each PCA component may include a housing having a connector, such as a flange, formed at each longitudinal end thereof. The flanges may be connected by fasteners (not shown), such as bolts or studs and nuts. Each PCA housing may have a bore therethrough corresponding to a bore of the production tubing 10p.

Each clamp 241u,b may include a housing having an annular inner portion and a pair of outer portions connected to the inner portion, such as by a threaded connection or flanges. Passages may be formed through the inner portion corresponding to each outer portion. An arm may be disposed in each outer portion. Each arm may have a piston formed at an outer end thereof and a band formed at an inner end thereof. Each band may be U-shaped. Each arm may be radially moveable between a disengaged position (shown) and an engaged position (not shown). The piston may divide each outer portion into a pair of chambers. An inner port may be formed through a wall of the inner housing portion corresponding to each outer housing portion and an outer port may be formed through each outer portion. Each port may be connected to the HPU 46. A proximity sensor, such as a contact switch, may be connected to each arm at a base of the respective band. Leads may connect each contact switch to the PLC 42p and may be flexible to accommodate movement of the arms. In operation, the arms may be engaged by supplying pressurized hydraulic fluid to the arm piston via outer ports and returning hydraulic fluid from the inner ports, thereby moving the arms inward in opposing fashion. The arms may be moved until the bands engage a corresponding profile, such as groove 62 (FIG. 2A), formed in an outer surface of the ESP 60, thereby longitudinally connecting the ESP to the PCA 240. Engagement of the bands may be detected by operation of the contact switches. Each clamp 241u,b may be locked in the engaged position hydraulically. Disengagement of the arms may be accomplished by reversing the hydraulic flow.

The shutoff valve 262 may be manually operated. Alternatively, the shutoff valve 262 may include an actuator (not shown), such as a hydraulic actuator connected to the HPU 46 by a flexible conduit. The annular BOP 265 may include a housing, a piston, and an annular packing. The annular BOP 265 may be the conical type (shown) or the spherical type (not shown). The packing, when sufficiently radially inwardly displaced, may sealingly engage an outer surface of the ESP 60 extending longitudinally through the housing.

The driver 250 may include one or more (two shown) units. The driver 250 may include a housing having an annular inner portion and an outer portion for each unit connected to the inner portion, such as by a threaded connection or flanges. Passages may be formed through the inner portion corresponding to each outer portion. An arm assembly may be disposed in each outer portion. Each arm assembly may include a piston and a wrench connected to the piston, such as by a flanged connection. Each arm assembly may be radially moveable between a disengaged position (shown) and an engaged position. The piston may divide each outer portion into a chamber and a recess. A port may be formed through each outer portion. Each port may be connected to the HPU 46 by an umbilical (not shown). The umbilical may include one or more conduits and/or cables, such as one or more power fluid conduits and a data cable. The power fluid may be hydraulic fluid and the power fluid conduits may be connected to the HPU 46. The data cable may be connected to the PLC 42p and may provide data communication between one or more sensors and the PLC.

Each wrench may include a motor, a reduction gear box, the sensors, and a socket. When fluid pressure is supplied to one port of the motor, the output shaft may rotate clockwise. This clockwise rotation of the output shaft may be transmitted via the gears to the socket, causing the socket to rotate in the bolt tightening direction, such as in counterclockwise. Since the output shaft may rotate continuously, the socket may rotate continuously in the bolt tightening direction. When fluid pressure is supplied to the other port of the motor, the output shaft may rotate in the opposite direction and thus the socket may tend to rotate in the opposite direction.

The sensors may include a video camera, a turns counter, and/or a torque sensor. The turns counter may measure an angle of rotation of the socket. The video camera may face the socket to facilitate engagement of the wrench with a bolt 91 (FIG. 2D) by the control room operator. The video camera may further include one or more lights. In operation, clear visibility fluid may be pumped into the PCA bore. The arms may be engaged with respective bolts 91 by supplying pressurized hydraulic fluid to the arm pistons via ports, thereby moving the arms inward in opposing fashion. The arm assemblies may be moved synchronously or independently by the control room operator. The control room operator may watch video of the sockets on the display of the control console 42c to facilitate engagement of the sockets with the bolts 91. The arm assemblies may be moved until the sockets engage the bolts 91. The wrenches may be operated to tighten the bolts. Torque and turns may be monitored to control tightening.

The driver may include a rotary table (not shown) operable to rotate each unit relative to the inner housing portion. The inner housing portion may be modified to enclose the units. The rotary table may include a stator connected to the modified inner housing portion, a rotor connected to each outer housing portion, a motor for rotating the rotor relative to the stator, a swivel for providing fluid and data communication between the wireline truck 40 and each wrench, and a bearing for supporting the rotor from the stator. Alternatively, the driver with the rotary table may only include one driver unit.

The flanged connection 90u,b may include an upper flange 90u connected to the pump section housing 95h, such as by a weld or a threaded connection, and a lower flange 90b connected to the pump section housing 95h, such as by a weld or a threaded connection. The flanged connection 90u,b, may include an auto orienting profile 92 having mating portions formed in each flange 90u,b. The upper flange 90u may have passages formed therethrough for receiving one or more threaded fasteners, such as the bolts 91. The passage may receive a shaft of each bolt 91 and a head of the bolt may engage an upper surface of the flange 90u when the shaft is inserted through the passage. A lower end of the section housing 95h may serve as a trap for the bolts 91, thereby preventing escape of the bolts 91 during insertion of the section housing into the PCA 240. To trap the bolts 91, the bolts may be disposed in the passages before the upper flange 90u is connected to the section housing 135h. The lower flange 90b may have threaded sockets 93 for receiving threaded shafts of respective bolts 91, thereby forming the flanged connection 90u,b. The passages and sockets 93 may be equally spaced around the respective flanges 90u,b at a predetermined increment, such as ninety degrees for four, sixty degrees for six, or forty-five degrees for eight.

The flanged connection 90u,b may further include a temporary connection for each flange 90u,b, such as shearable fasteners 94. One of the shearable fasteners 94 may torsionally connect the upper shaft coupling 93 of the first pump section 95 to the lower flange 90b and another one of the shearable fasteners 94 may torsionally connect the upper shaft coupling 93 of the second pump section 95 to the upper flange 90u. The shaft couplings 93 may be temporarily fastened in mating positions such that when the auto-orienting profile aligns the flanges 90u,b, the shaft couplings 93 may also be aligned. The shearable fasteners 94 may fracture in response to operation of the motor 70 once the ESP 60 has landed in the dock 15.

To prepare for insertion, the ESP 60 may be assembled into two or more deployment sections, such as four. The first deployment section may include the motor 70 and the lander 65. The second deployment section may include the shaft seal 75. The third deployment section may include the inlet 80 and the first pump section 85. The fourth deployment section may include the second pump section 95 and the packoff 99. A length of each deployment section (plus running tool 59) may be less than or equal to a length of the tool housing 205h. The arrangement and number of deployment sections may vary based on parameters of the ESP 60, such as number of stages and components.

The wireline 50 may be inserted into the seal head 210 of the lubricator 200 and connected to a cablehead of the running tool 59. The running tool 59 may then be connected to the first deployment section. The first deployment section may be inserted into the tool housing 205. The lubricator 200 and first deployment section may be hoisted over the PCA 240 using the wireline 50 and/or a crane (not shown).

The crane may suspend the lubricator 200 while the wireline winch 47 is operated to lower the first deployment section until the lander 65 and a lower portion of the motor 70 are accessible. The motor 70 may then be serviced, such as by adding motor oil thereto. The lubricator 200 may be lowered onto the PCA 240 using the crane. The lubricator tee 215 may then be fastened to the upper clamp 241u, such as by a flanged connection. The seal head 210 may be operated to engage the wireline 50. The master 31 and swab 33 valves may then be opened.

The first deployment section may be lowered into the PCA 240 using the wireline 50 until the motor groove 62 is aligned with the upper clamp 241u. The upper clamp 241u may then be operated to engage the motor 70, thereby supporting the first deployment section. The annular BOP 265 may then be operated to engage the packing with an outer surface of the motor 70. Since a bottom of the motor 70 may be sealed, the first deployment section may plug a bore of the PCA 240, thereby sealing an upper portion of the PCA from wellbore pressure. The lubricator connection to the PCA 240 may be disassembled. The upper clamp 241u may also secure the first deployment section from being ejected from the PCA 240 due to wellbore pressure. The running tool 59 may be operated to release the first deployment section using the wireline 50. The lubricator 200 and running tool 59 may then be removed. The second deployment section may be inserted into the tool housing 205 and connected to the running tool 59. The lubricator 200 and second deployment section may be hoisted over the PCA 240 using the wireline 50 and/or the crane.

The crane may suspend the lubricator 200 while the wireline winch 47 is operated to lower the second deployment section until the lower flange 61 of the shaft seal 75 seats on the upper flange 61 of the motor 70. During lowering, the flanges 61 may be manually aligned and the upper motor shaft coupling 63 may be manually aligned and engaged with the lower seal shaft coupling 63. The flanged connection 61 may be assembled. The lubricator 200 may be lowered onto the PCA 240 using the crane 90. The lubricator tee 215 may again be fastened to the PCA 240. The seal head 210 may again be operated to engage the wireline 50. The annular BOP 265 may be disengaged from the motor 70. The upper clamp 241u may be operated to release the motor 70. The first and second deployment sections may be lowered into the PCA 240 until the shaft seal groove 62 is aligned with the upper clamp 241u. The upper clamp 241u may then be operated to engage the shaft seal 75, thereby supporting the first and second deployment sections. The annular BOP 265 may then be operated to engage an outer surface of the shaft seal 75.

The lubricator connection to the PCA 240 may be disassembled. The running tool 59 may be operated to release the second deployment section using the wireline 50. The lubricator 200 and running tool 59 may then be removed. The third deployment section may be inserted into the tool housing 205 and connected to the running tool 59. The lubricator 200 and third deployment section may be hoisted over the PCA 240 using the wireline 80 and/or the crane. The crane may suspend the lubricator 200 while the wireline winch 47 is operated to lower the third deployment section until the lower first pump section flange 61 seats on the upper shaft seal flange 61. During lowering, the flanges 61 may be manually aligned and the upper seal shaft coupling 63 may be manually aligned and engaged with the lower pump section shaft coupling 63. The flanged connection 101 may be assembled. The lubricator 200 may be lowered onto the PCA 240 using the crane 90. The lubricator tee 215 may again be fastened to the PCA 240. The seal head 210 may again be operated to engage the wireline 50. The annular BOP 265 may be disengaged from the shaft seal 75. The upper clamp 241u may be operated to release the shaft seal 75. The first, second, and third deployment sections may be lowered into the PCA 240 until the first pump section groove 62 is aligned with the lower clamp 241b. The lower clamp 241b may then be operated to engage the first pump section 85, thereby supporting the deployment sections.

Since the third and fourth deployment sections may have open through-bores, the open deployment sections may not be used as plugs and the isolation valve 262 may be used to close the upper portion of the PCA. The running tool 59 may be operated to release the third deployment section using the wireline 50. The running tool 59 may be raised from the PCA 240 into the lubricator 200 using the wireline 50. The isolation valve 262 may be closed. The lubricator connection to the PCA 240 may be disassembled. The lubricator 200 and running tool 59 may then be removed. The fourth deployment section may be inserted into the tool housing 205 and connected to the running tool. The lubricator 200 and fourth deployment section may be hoisted over the PCA 240 using the wireline 50 and/or the crane.

The lubricator 200 may be lowered onto the PCA 240 using the crane. The lubricator tee 215 may again be fastened to the PCA 240. The seal head 210 may again be operated to engage the wireline 50. The isolation valve 262 may be opened. Visibility fluid may be injected into the PCA 240. The running tool 59 and fourth deployment section may be lowered into the PCA 240 until the upper first pump section flange 90u is proximate to the lower second pump section flange 90b. The fourth deployment section may be slowly lowered to engage the parts of the auto-orienting profile 92 for aligning the flanges 90u,b. Once the auto-orienting profile 92 has mated, the driver arm assemblies 53 may be operated to engage the bolts 91.

Each driver motor may be operated to rotate the bolts 91 into respective sockets 93. Torque and turns may be monitored by the control room operator and/or the PLC 42p to ensure proper assembly. The arm assemblies 53 may be disengaged from the upper flange 130u. Once the flanged connection 90ub, has been fully assembled, the lower clamp 241b may be operated to disengage the first pump section housing 95h. The cable injector 100 may then be connected to a top of the lubricator 200 and closed/assembled around the wireline 50. The cable injector 100 may then be operated to lower the assembled ESP 60 into the wellbore 5w.

Alternatively, the tool housing 205 may have a length corresponding to a length of the ESP 60, thereby obviating the need for the PCA 240.

FIG. 6A illustrates a power cable deployed ESP 360 for use with a modified LARS. The modified LARS may be similar to the LARS 1 except that the LARS truck components may be mounted on a skid frame and the power converter 45 may output a medium voltage DC power signal to the wireline for driving the ESP 360. The medium voltage power signal may be greater than or equal to one kilovolt, such as three to ten kilovolts. The LARS PLC 42p may further include a data modem and a multiplexer for modulating and multiplexing a data signal to/from the downhole controller with the DC power signal.

The ESP 360 may include the electric motor 70, a power conversion module (PCM) 361, the seal section 75, the inlet 80, the pump 85, a lander 363, an outlet 364, and a cablehead 365. Additionally, the pump 85 may be a first pump section and the ESP 360 may further include the second pump section (see pump section 95). Housings of each of the ESP components may be longitudinally and torsionally connected, such as by flanged or threaded connections. The cablehead 365 may include a cable fastener (not shown), such as slips or a clamp for longitudinally connecting the ESP 360 to the wireline 50.

The wireline 50 may be longitudinally coupled to the cablehead 365 by a shearable connection (not shown). The wireline 50 may be sufficiently strong so that a margin exists between the deployment weight and the strength thereof. The cablehead 365 may further include a fishneck so that if the ESP 360 become trapped in the wellbore 5w, such as by buildup of sand, the wireline 50 may be freed from rest of the components by operating the shearable connection and a fishing tool (not shown), may be deployed to retrieve the ESP 360.

The cablehead 365 may also include leads extending therethrough. The leads may provide electrical communication between the conductors of the wireline 50 and the PCM 361. The PCM 361 may include a power supply, a motor controller (not shown), a modem (not shown), and multiplexer (not shown). The motor controller may be similar to the motor controller of the control unit 39. The power supply may include one or more DC/DC converters, each converter including an inverter, a transformer, and a rectifier for converting the DC power signal into an AC power signal and reducing the voltage from medium to low. Each converter may be a single phase active bridge circuit as discussed and illustrated in PCT Publication WO 2008/148613, which is herein incorporated by reference in its entirety. The power supply may include multiple DC/DC converters in series to gradually reduce the DC voltage from medium to low. For the SRM and BLDC motors, the low voltage DC signal may then be supplied to the motor controller. For the induction motor, the power supply may further include a three-phase inverter for receiving the low voltage DC power signal from the DC/DC converters and outputting a three phase low voltage AC power signal to the motor controller.

The PCM modem and multiplexer may demultiplex a data signal from the DC power signal, demodulate the signal, and transmit the data signal to the motor controller. The motor controller may be in data communication with one or more sensors (not shown) distributed throughout the ESP 360. A pressure and temperature (PT) sensor may be in fluid communication with the reservoir fluid 7 entering the inlet 80. A gas to oil ratio (GOR) sensor may also be in fluid communication with the reservoir fluid 7 entering the inlet 80. A second PT sensor may be in fluid communication with the reservoir fluid 35 discharged from the outlet 364. A temperature sensor (or PT sensor) may be in fluid communication with the lubricant to ensure that the motor 70 and PCM 361 are being sufficiently cooled. Multiple temperature sensors may also be included in the PCM 361 for monitoring and recording temperatures of the various electronic components. A voltage meter and current (VAMP) sensor may be in electrical communication with the wireline 50 to monitor power loss therefrom. A second VAMP sensor may be in electrical communication with the power supply output to monitor performance of the power supply. Further, one or more vibration sensors may monitor operation of the motor 70, the pump 85, and/or the seal section 75. A flow meter may be in fluid communication with the outlet 364 for monitoring a flow rate of the pump 85. Utilizing data from the sensors, the motor controller may monitor for adverse conditions, such as pump-off, gas lock, or abnormal power performance and take remedial action before damage to the pump 85 and/or motor 70 occurs.

In anticipation of depletion, the production tubing string 310p may have a landing nipple 315 installed at a lower end thereof. The landing nipple 315 may have a seal bore, a torsional coupling, such as an auto-orienting castellation, and a stop shoulder. The lander 363 may have a tubing seal, a torsional coupling, such as an auto-orienting castellation, and a stop shoulder. Engagement of the lander 363 with the landing nipple 315 may engage the tubing seal with the seal bore, align the castellations, and engage the stop shoulders, thereby longitudinally supporting the ESP 360 from the production tubing string 310p and torsionally connecting the ESP to the production tubing string, and isolating the inlet 64i from the outlet 640.

Alternatively, the ESP 360 may include an isolation device having an anchor and a packer instead of the lander 363.

FIG. 6B illustrates insertion of the ESP 360 into the wellbore 5w using the cable injector 100, according to another embodiment of the present disclosure. FIG. 6C illustrates operation of the power cable deployed ESP 360. Referring specifically to FIG. 6B, the tree valves 31, 33 may be opened. The ESP 360, running tool 59 and seal head 210 may be assembled, the seal head 210 may be connected to the tree 30, and the ESP and running tool may be lowered and suspended in the tree 30, wellhead 10h, and/or upper portion of the wellbore 5w by the winch 47. The cable injector 100 may then be connected to a top of the seal head 210 and closed/assembled around the wireline 50. The cable injector 100 may then be operated to lower the ESP 360 into the wellbore 5w using the wireline 50 until the motor 70 is adjacent to the SSV 3.

Referring specifically to FIG. 6C, the seal head 210 may then be operated to engage the wireline 50 and the SSV 3 opened. The cable injector 100 may then continue to lower the ESP 360 to the deployment depth. Once the lander 363 has engaged the landing nipple 315, the cable injector 100 may be disassembled and disconnected from the seal head 210. The ESP 360 may then be operated to pump production fluid 7 from the wellbore 5w.

Alternatively, the seal head may be operated to engage the wireline before lowering the ESP 360 into the wellbore. Alternatively, the rest of the lubricator 200 may be used to assemble, insert, and/or deploy the ESP 360, as discussed above for the ESP 60.

FIGS. 7A-7D illustrate insertion of the power cable deployed ESP 360 into the wellbore 5w using the cable injector 100, according to another embodiment of the present disclosure. FIG. 7E illustrates operation of the power cable deployed ESP 360. Referring specifically to FIG. 7A, the tree valves 31, 33 may be opened. The ESP 360, running tool 59 and one 225u of the stuffing boxes 225u,b may be assembled, the stuffing box 225u may be connected to the tree 30, and the ESP and running tool may be suspended in the tree 30 and/or upper portion of the wellbore 5w by the winch 47. The cable injector 100 may then be connected to a top of the stuffing box 225u and closed/assembled around the wireline 50. The cable injector 100 may then be operated to lower the ESP 360 into the wellbore 5w using the wireline 50 until the motor 70 is adjacent to the SSV 3 and/or the deployment depth.

Referring specifically to FIG. 7B, the winch 47 may then be locked to suspend the ESP 360. The cable injector 100 may be disassembled and disconnected from the seal head 210. A mold 301 may be assembled around the wireline 50 and connected to a top of the stuffing box 225u. A more detailed discussion regarding use of the mold 301 may be found in U.S. patent application Ser. No. 13/447,001 (Atty. Dock. No. ZEIT/0006US), which is herein incorporated by reference in its entirety.

The mold 301 may be delivered to the wellsite by a service truck (not shown). The service truck may include a reaction injector and a crane or platform to lift the mold to a top of the stuffing box. The reaction injector may include a pair of supply tanks each having a liquid reactive component (aka resin and hardener) stored therein. The supply tanks or the components may or may not be heated. The service truck may further include a pair of feed pumps, each having an inlet connected to a respective supply tank. An outlet of each supply pump may be connected to a mix head and an outlet of the mix head may connect to the mold 301. The service truck may further include an HPU for powering the supply pumps. The service truck may further include a controller for proportioning the feed pumps. The feed pumps may be operated to simultaneously supply the liquid reactive components to the mix head. The mix head may impinge the liquid components to begin polymerization of the sealant mixture 345. The sealant mixture 345 may continue from the mix head into the mold 301.

The mold 301 may include a split housing 305 and upper and lower seals (not shown). The housing 305 may include a pair of mating semi-tubular segments 305a,b. Each housing segment 305a,b may have radial couplings, such as flanges 308, formed therealong and half of a longitudinal coupling (not shown), such as a flange, formed at one or both longitudinal ends thereof. The radial flanges 308 of each housing segment 305a,b may be connected to the mating radial flanges by fasteners 307, such as bolts and nuts. A gasket 309 may be disposed in a groove formed in one of the housing segments for sealing the radial connection. Each seal may include a pair of mating semi-annular segments.

An inner diameter of the mold housing 305 may be slightly greater than an outer diameter of the wireline 50, thereby forming an annulus 312 between the mold housing and the wireline. The housing 305 may have a sprue 306 formed through a wall of one of the segments 305a,b and in fluid communication with the annulus 312. An inner diameter of the mold seals may be slightly less than an outer diameter of the wireline 50 so that the mold seals engage an outer surface of the wireline the mold 301 is assembled.

Referring specifically to FIG. 7C, the sealant 345 may be a polymer, such as an elastomer or thermoplastic elastomer. Once the mold 301 has been assembled around the wireline 50, the mix head may be lifted to the mold 301 by the service truck crane or the service truck platform may lift the reaction injector to the mold 301. The mix head may be connected to the sprue 306. The supply pumps may then be operated to pump the liquid reactants to the mix head. The sealant mixture 345 may continue from the mix head into the mold 301. Air displaced by the sealant mixture 345 may vent from the mold via leakage through and along the armor 57i,o. The sealant mixture 345 may flow around and along the annulus 312 until the sealant mixture 345 encounters the seals. Pressure in the mold 301 may increase and the sealant mixture 345 may be forced into the armor 57i,o. Sealant penetration into the wireline 50 may be stopped by the outer jacket 56. Pumping of the sealant mixture 345 may continue until the mold 301 is filled. The mold 301 may be heated by exothermic polymerization of the mixture 345. A melting temperature of the mold seals, gasket 309, and outer jacket 56 may be suitable to withstand the exothermic reaction.

Referring specifically to FIG. 7D, once the sealant 345 has cured and cooled to at least a point sufficient to maintain structural integrity, the mix head may be disconnected from the mold 301 and the mold 301 may be disconnected from the stuffing box 225u. The fasteners 307 may then be removed. The service truck may further include a hydraulic spreader. The spreader may be connected to the mold 301 and operated to separate the mold. The service truck may stow the mold 301 and mix head and leave the wellsite. A length of the sealed portion 350 may correspond to a length of a seal of the stuffing box 225u and be substantially less than a length of the wireline 50. An outer diameter of the sealed portion 350 may be slightly greater than an outer diameter of the rest of the wireline 50.

Referring specifically to FIG. 7D, the stuffing box 225u may then be operated to engage the wireline 50 and the SSV 3 opened. The winch 47 may then be unlocked and operated to lower the ESP 360 to deployment depth. Alternatively, the cable injector 100 may be reinstalled around the sealed portion 350 and operated to lower the ESP 360 to deployment depth. As the ESP 360 is lowered, the sealed portion 350 may be lowered into alignment with the stuffing box seal as the lander 363 engages with the landing nipple 315. The ESP 360 may then be operated to pump production fluid 7 from the wellbore 5w.

While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow.

Claims

1. An injector for deploying a cable into a wellbore, comprising:

a traction assembly comprising at least a stationary segment and a movable segment, each segment comprising: a drive sprocket; an idler sprocket; a track looped around and between the sprockets; a set of grippers fastened to and disposed along the respective track,

a frame: connected to the stationary segment, having a coupling for connection to a pressure control assembly (PCA), and having a passage for receiving the cable; and

a motor torsionally connected to the drive sprocket of the stationary segment.

2. The injector of claim 1, wherein each gripper has an opening for receiving a cog of the respective sprockets.

3. The injector of claim 2, wherein each track is a belt having a passage adjacent each gripper for passing the cog.

4. The injector of claim 1, wherein each gripper:

is made from a metal, alloy, or cermet,

has a recess formed therein for receiving the cable, and

has teeth formed in the recess.

5. The injector of claim 4, wherein each gripper has wings extending transversely from the recess.

6. The injector of claim 1, wherein the movable segment is pivoted to the stationary segment for swinging between an open position for receiving the cable and a closed position for deploying the cable.

7. The injector of claim 6, wherein:

each segment further comprises a gear torsionally connected to the respective drive sprocket, and

the gears mesh upon closing of the movable segment.

8. The injector of claim 6, wherein each segment further comprises a body having a hinge knuckle formed at each inner end thereof.

9. The injector of claim 1, wherein each segment further comprises:

a tensioner operable to tighten the respective track, and

a counter bearing for supporting the tightened track.

10. The injector of claim 1, wherein the traction assembly further comprises a second movable segment.

11. The injector of claim 1, further comprising a linear actuator operable to move the movable segment toward and away from the stationary segment.

12. A launch and recovery system (LARS), comprising:

the injector of claim 1;

a winch having the cable;

a boom for guiding the cable into the PCA;

the PCA for connection to a production tree; and

a downhole assembly of an artificial lift system for deployment into the wellbore using the cable.

13. The LARS of claim 12, further comprising a stuffing box having a coupling for connection to the PCA and a coupling for connection to the injector.

14. The LARS of claim 13, further comprising a seal head having the stuffing box and a grease injector.

15. The LARS of claim 14, further comprising a lubricator having the seal head and a tool housing.

16. A method of deploying a downhole tool into a wellbore, comprising:

connecting the downhole tool to a cable;

lowering the downhole tool into a pressure control assembly (PCA) and wellhead adjacent to the wellbore using the cable;

after lowering the downhole tool, connecting a cable injector to the PCA and closing the cable injector around the cable; and

operating the cable injector, thereby injecting the cable into the wellbore and lowering the downhole tool to a deployment depth in the wellbore.

17. The method of claim 16, wherein the downhole tool is lowered by:

assembling the PCA onto a production tree connected to the wellhead;

inserting a first deployment section of the downhole tool into a lubricator;

landing the lubricator onto the PCA;

connecting the lubricator to the PCA;

lowering the first deployment section into the PCA;

engaging a clamp of the PCA with the first deployment section;

after engaging the clamp, isolating an upper portion of the PCA from a lower portion of the PCA by engaging a seal of the PCA with the first deployment section; and

after isolating the PCA, removing the lubricator from the PCA.

18. The method of claim 16,

further comprising connecting a stuffing box to the PCA,

wherein the cable injector is connected to the PCA by being connected to the stuffing box.

19. The method of claim 18, further comprising:

engaging a mold with an outer surface of the cable;

injecting sealant into the mold and into armor of the cable, thereby sealing a portion of the cable;

engaging a seal of the stuffing box with the sealed portion of the cable; and

operating the downhole tool using the cable.

20. The method of claim 18, wherein:

the stuffing box is part of a seal head having a grease injector, and

the method further comprises: engaging the seal head with the cable; and operating the downhole tool using the cable.

21. The method of claim 16, wherein:

the downhole tool is an electrical submersible pump (ESP), and

the method further comprises operating the ESP to pump production fluid from the wellbore.

22. The method of claim 21, wherein the ESP is operated by receiving a power signal from the cable.

23. The method of claim 21, wherein:

the ESP lands into a dock of production tubing at the deployment depth, and

the ESP is operated by receiving a power signal from the dock.

24. The method of claim 23, wherein:

the PCA is mounted on a production tree connected to the wellhead,

the method further comprises: disconnecting the cable from the ESP; retrieving the cable from the wellbore; and removing the PCA and cable injector from the production tree.

25. The method of claim 16, wherein the cable is coaxial wireline.