US20140102721A1 - Cable injector for deploying artificial lift system - Google Patents
Cable injector for deploying artificial lift system Download PDFInfo
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- US20140102721A1 US20140102721A1 US14/049,420 US201314049420A US2014102721A1 US 20140102721 A1 US20140102721 A1 US 20140102721A1 US 201314049420 A US201314049420 A US 201314049420A US 2014102721 A1 US2014102721 A1 US 2014102721A1
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Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/08—Apparatus for feeding the rods or cables; Apparatus for increasing or decreasing the pressure on the drilling tool; Apparatus for counterbalancing the weight of the rods
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
- E21B33/072—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells for cable-operated tools
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
- E21B23/14—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for displacing a cable or a cable-operated tool, e.g. for logging or perforating operations in deviated wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/22—Handling reeled pipe or rod units, e.g. flexible drilling pipes
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
- E21B43/121—Lifting well fluids
- E21B43/128—Adaptation of pump systems with down-hole electric drives
Definitions
- Embodiments of the present disclosure generally relate to a cable injector for deploying an artificial lift system.
- ESPs electric submersible pumps
- 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.
- 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.
- PCA pressure control assembly
- the injector further includes a motor torsionally connected to the drive sprocket of the stationary segment.
- 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.
- PCA pressure control assembly
- 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.
- ESP electric submersible pump
- FIGS. 3A , 3 C, and 3 D 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.
- PCA pressure control assembly
- 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.
- 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 ).
- PCA pressure control assembly
- BOPs blowout preventers
- FIG. 4A blowout preventers
- a wellbore 5 w has been drilled from a surface 5 s of the earth into a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir 6 ( FIG. 4A ).
- a string of casing 10 c has been run into the wellbore 5 w and set therein with cement (not shown).
- the casing 10 c has been perforated 9 ( FIG. 4B ) to provide to provide fluid communication between the reservoir 6 and a bore of the casing 10 c .
- a wellhead 10 h has been mounted on an end of the casing string 10 c .
- a string of production tubing 10 p extends from the wellhead 10 h to the reservoir 6 to transport production fluid 7 ( FIG. 4C ) from the reservoir 6 to the surface 5 s .
- a packer 8 ( FIG. 4A ) has been set between the production tubing 10 p and the casing 10 c to isolate an annulus 10 a ( FIG. 4B ) formed between the production tubing and the
- a production (aka Christmas) tree 30 has been installed on the wellhead 10 h .
- 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 10 p , travel through the tubing bore to the surface 5 s .
- 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.
- ALS artificial lift system
- the ALS may include a control unit 39 ( FIG. 4C ) located at the surface 5 s , a power cable 20 , and a downhole assembly, such as an electrical submersible pump (ESP) 60 ( FIGS. 2A-2D ).
- the downhole assembly may include an electrical submersible compressor.
- the production tubing string 10 p 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 4 u,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 10 h but allowing flow from the wellhead to the reservoir.
- 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 10 p to the wellhead 10 h .
- 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 4 u,b may be a pressure or pressure and temperature (PT) sensor.
- the sensors 4 u,b may be located along the production tubing 10 p so that the upper sensor 4 u is in fluid communication with an outlet of the ESP 60 and a lower sensor 4 b is in fluid communication with an inlet 80 ( FIG. 2C ) of the ESP 60 .
- the sensors 4 u,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 4 u,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 10 p 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 10 p .
- 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 10 p.
- 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.
- the LARS 1 may further include a lubricator 200 ( FIG. 5A ) for deploying the ESP 60 .
- 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 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 .
- the deployment cable may be slickline or wire rope.
- the control room 42 may include a control console 42 c and a programmable logic controller (PLC) 42 p .
- PLC programmable logic controller
- 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 .
- 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 42 c 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 10 p .
- 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 29 i,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)).
- EPDM ethylene propylene diene monomer
- 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 .
- PTFE polytetrafluoroethylene
- 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 29 i,o may be made from one or more layers 29 i,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 29 i,o may include two contra-helically wound layers 29 i,o of wire, fiber, or strip.
- a buffer (not shown) may be disposed between the armor layers 29 i,o .
- the buffer may be tape and may be made from the lubricative material.
- 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.
- 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 57 i,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 57 i,o and be made from a fluid-resistant dielectric material, such as polyethylene or polyurethane.
- the armor 57 i,o may be made from one or more layers 57 i,o of the high strength material to support the ESP 60 .
- the armor 57 i,o may include two contra-helically wound layers 57 i,o of wire, fiber, or strip.
- 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.
- a buffer 58 may be disposed between the armor layers 57 i,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 70 h - 95 h of each of the ESP components may be longitudinally and torsionally connected, such as by flanged connections 61 , 90 u,b .
- the flanged connections 90 u,b may be replaced by the flanged connections 61 .
- Shafts 70 s - 95 s of the motor 70 , shaft seal 75 , inlet 80 , and pump sections 85 , 95 may be torsionally connected, such as by shaft couplings 63 .
- the housings 70 h - 95 h 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 70 s . In operation, the motor 70 may rotate the drive shaft 70 s , thereby driving the pump shafts 85 s , 95 s of the pump 85 , 95 .
- the drive shaft 70 s may be directly drive the pump shaft 85 s , 95 s (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.
- 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 10 p .
- the packoff 99 may further include an inner profile for engagement with the running tool 59 .
- 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 85 s , 95 s , 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.
- 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.
- 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.
- 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 4 u,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 .
- 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.
- 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 .
- 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 .
- 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.
- 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.
- 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 , 3 C, and 3 D 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 101 d and a movable segment 101 p .
- the stationary segment 101 d may be connected to a base 103 b 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 103 f , connected to the base 103 b , such as by one or more fasteners or a weld.
- the flange 103 f may mate with a corresponding upper flange of the BOPs 38 and be connected thereto by one or more fasteners.
- 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 103 f and base 103 b for receiving the wireline 50 .
- Each segment 101 d,p may include a respective: body 105 d,p , conveyor 106 d,p , tensioner 107 p (stationary tensioner not shown), and counter bearing 116 d,p .
- Each body 105 d,p may be rectangular and have a cavity formed therein.
- Each body 105 d,p may have an open inner face for operation of the respective conveyor 106 d,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 105 d,p may have a respective coupling, such as a hinge knuckle 117 p,d , formed at each inner end thereof.
- the movable segment 101 p may initially be connected to the stationary segment 101 d , such as pivoted, by meshing a first mating pair of the knuckles 117 p,d and inserting a hinge pin 104 a through the meshed first pair such that the movable segment may swing between the open and closed positions.
- the movable segment 101 p may then be closed by meshing a second mating pair of the knuckles 117 p,d and inserting a latch pin 104 b 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 5 w.
- Each conveyor 106 d,p may include a respective: track, such as a belt 108 d,p , gear 109 d,p , idler sprocket 110 d,p , drive sprocket 111 d,p , idler hub (not shown), drive hub 112 d,p , and set 113 d,p of grippers 113 .
- the tracks may be roller chains.
- Each gripper 113 may be fastened to the respective belt 108 d,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 113 d,p may include grippers 113 spaced along an outside of the respective belt 108 d,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 113 d,p of grippers 113 may engage a fraction of an outer surface of the wireline 50 .
- each set may engage one-half of the wireline outer surface.
- 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.
- 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 .
- 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 57 o .
- a receiver opening may also be formed through each central portion for receiving a cog 114 p,d of the respective sprockets 110 p,d , 111 p,d .
- a corresponding passage may be formed through the belt adjacent each receiver opening for passage of the cog 114 p,d therethrough.
- a length of each gripper and the interval between adjacent grippers may correspond to a pitch of the respective sprockets 110 p,d , 111 p,d .
- Each receiver opening may be shaped to mesh with the cog 114 p,d such that the gripper 113 (and belt) seats onto the adjacent bottom lands of the sprocket 110 p,d , 111 p,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 108 d,p via the fasteners.
- Each belt 108 d,p may be endless and loop around and between the respective sprockets 110 p,d , 111 p,d .
- Each belt 108 d,p may have a flat or trapezoidal cross-section.
- Each belt 108 d,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 108 d,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 57 o.
- Each hub 112 d,p may be mounted to the respective body 105 d,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 110 p,d , 111 p,d may be disposed on a respective hub 112 d,p and torsionally connected thereto, such as by interference fit or fastener.
- Each gear 109 d,p may be disposed on a respective drive hub 112 d,p and torsionally connected thereto, such as by interference fit or fastener.
- the stationary drive hub 112 d may also have a shaft coupling (not shown) for receiving a shaft coupling (not shown) of a drive shaft 102 d of the motor 102 , thereby torsionally connecting the drive hub to the drive shaft.
- the gears 109 d,p may be configured to mesh upon closing of the cable injector 100 , thereby torsionally connecting the stationary drive hub 112 d to the movable drive hub 112 p.
- 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 5 w and pull the wireline from the wellbore.
- the drive motor 102 may have a housing 102 h connected to a bracket 103 t 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 41 a,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 102 h .
- the rotor may be torsionally connected to the drive shaft 102 d .
- 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 102 h 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.
- the motor 102 may have an additional hydraulic port for supplying the actuator.
- the motor 102 may be electric or pneumatic.
- Each tensioner 107 p 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 107 p may be in fluid communication with the HPU 46 via a flexible conduit, such as a hose 43 (common or individual). Each tensioner 107 p may be operated to extend the roller into engagement with the respective belt 108 d,p , thereby tightening the respective belt 108 d,p and gripper set 113 d,p into engagement with the respective sprockets 110 p,d , 111 p,d .
- Each counter bearing 116 p may include a base connected to the respective body 105 d,p and one or more rollers mounted along the base for rotation relative thereto. As each tensioner 107 p tightens the respective belt 108 d,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.
- 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.
- a linear actuator such as a piston and cylinder assembly
- 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.
- each belt may include segments spaced apart to form the cog passage instead of being continuous and the grippers may link the belt segments.
- the cable injector 100 may be used with other types of cable, such as slickline or wire rope.
- 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 5 w using the LARS 1 .
- FIG. 4C illustrates operation of the ESP 60 .
- 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 10 h , and/or upper portion of the wellbore 5 w 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 101 p in the open position or without the movable segment. If connected without the movable segment 101 p , the movable segment 101 p may then be connected to the stationary segment 101 d in the open position. The movable segment 101 p may then be closed and secured around the wireline 50 .
- the hoses 41 a,b and 43 may then be connected to the cable injector 100 .
- the tensioners 107 p may then be operated to engage the respective belts 108 d,p with the sprockets 110 d,p , 111 d,p .
- the winch 47 may be idled and the drive motor 102 may then be operated to lower the ESP 60 into the wellbore 5 w 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 10 p , the cable injector 100 may push the wireline 50 into the wellbore 5 w.
- the body 105 d 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.
- a second coupling such as a flange
- 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 10 p to align the wet-matable connector 16 , 66 .
- 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 5 w .
- 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 5 w . 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 225 u,b and a grease injector 230 .
- Each stuffing box 225 u,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).
- the piston 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.
- the PCA 240 may include one or more clamps 241 u,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 10 p.
- Each clamp 241 u,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 42 p and may be flexible to accommodate movement of the arms.
- 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 241 u,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 42 p 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.
- the output shaft 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.
- 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.
- 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 42 c 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.
- the driver with the rotary table may only include one driver unit.
- the flanged connection 90 u,b may include an upper flange 90 u connected to the pump section housing 95 h , such as by a weld or a threaded connection, and a lower flange 90 b connected to the pump section housing 95 h , such as by a weld or a threaded connection.
- the flanged connection 90 u,b may include an auto orienting profile 92 having mating portions formed in each flange 90 u,b .
- the upper flange 90 u 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 90 u when the shaft is inserted through the passage.
- a lower end of the section housing 95 h 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 .
- the bolts may be disposed in the passages before the upper flange 90 u is connected to the section housing 135 h .
- the lower flange 90 b may have threaded sockets 93 for receiving threaded shafts of respective bolts 91 , thereby forming the flanged connection 90 u,b .
- the passages and sockets 93 may be equally spaced around the respective flanges 90 u,b at a predetermined increment, such as ninety degrees for four, sixty degrees for six, or forty-five degrees for eight.
- the flanged connection 90 u,b may further include a temporary connection for each flange 90 u,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 90 b 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 90 u .
- the shaft couplings 93 may be temporarily fastened in mating positions such that when the auto-orienting profile aligns the flanges 90 u,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 .
- 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 205 h .
- 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 241 u , 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 241 u .
- the upper clamp 241 u 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 241 u 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 .
- 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 241 u 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 241 u .
- the upper clamp 241 u 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 .
- 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 241 u 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 241 b .
- the lower clamp 241 b may then be operated to engage the first pump section 85 , thereby supporting the deployment sections.
- 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 90 u is proximate to the lower second pump section flange 90 b .
- the fourth deployment section may be slowly lowered to engage the parts of the auto-orienting profile 92 for aligning the flanges 90 u,b .
- 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 42 p to ensure proper assembly.
- the arm assemblies 53 may be disengaged from the upper flange 130 u . Once the flanged connection 90 ub , has been fully assembled, the lower clamp 241 b may be operated to disengage the first pump section housing 95 h .
- 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 5 w.
- 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 42 p 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 .
- 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 5 w , 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.
- the low voltage DC signal may then be supplied to the motor controller.
- 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.
- a voltage meter and current (VAMP) sensor may be in electrical communication with the wireline 50 to monitor power loss therefrom.
- VAMP voltage meter and current
- a second VAMP sensor may be in electrical communication with the power supply output to monitor performance of the power supply.
- 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.
- the production tubing string 310 p 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 310 p and torsionally connecting the ESP to the production tubing string, and isolating the inlet 64 i from the outlet 640 .
- 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 5 w using the cable injector 100 , according to another embodiment of the present disclosure.
- FIG. 6C illustrates operation of the power cable deployed ESP 360 .
- 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 10 h , and/or upper portion of the wellbore 5 w 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 5 w using the wireline 50 until the motor 70 is adjacent to the SSV 3 .
- 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 5 w.
- the seal head may be operated to engage the wireline before lowering the ESP 360 into the wellbore.
- 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 5 w using the cable injector 100 , according to another embodiment of the present disclosure.
- FIG. 7E illustrates operation of the power cable deployed ESP 360 .
- the tree valves 31 , 33 may be opened.
- the ESP 360 , running tool 59 and one 225 u of the stuffing boxes 225 u,b may be assembled, the stuffing box 225 u 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 5 w by the winch 47 .
- the cable injector 100 may then be connected to a top of the stuffing box 225 u and closed/assembled around the wireline 50 .
- the cable injector 100 may then be operated to lower the ESP 360 into the wellbore 5 w using the wireline 50 until the motor 70 is adjacent to the SSV 3 and/or the deployment depth.
- 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 225 u .
- 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
- 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 305 a,b .
- Each housing segment 305 a,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 305 a,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 305 a,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.
- the sealant 345 may be a polymer, such as an elastomer or thermoplastic elastomer.
- 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 57 i,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 57 i,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.
- the mix head may be disconnected from the mold 301 and the mold 301 may be disconnected from the stuffing box 225 u .
- 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 225 u 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 .
- the stuffing box 225 u 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.
- the cable injector 100 may be reinstalled around the sealed portion 350 and operated to lower the ESP 360 to deployment depth.
- 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 5 w.
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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
- 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.
- 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.
- 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.
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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. -
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 awireleine 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 5 w has been drilled from asurface 5 s of the earth into a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir 6 (FIG. 4A ). A string ofcasing 10 c has been run into thewellbore 5 w and set therein with cement (not shown). Thecasing 10 c has been perforated 9 (FIG. 4B ) to provide to provide fluid communication between thereservoir 6 and a bore of thecasing 10 c. Awellhead 10 h has been mounted on an end of thecasing string 10 c. A string ofproduction tubing 10 p extends from thewellhead 10 h to thereservoir 6 to transport production fluid 7 (FIG. 4C ) from thereservoir 6 to thesurface 5 s. A packer 8 (FIG. 4A ) has been set between theproduction tubing 10 p and thecasing 10 c to isolate anannulus 10 a (FIG. 4B ) formed between the production tubing and the casing fromproduction fluid 7. - A production (aka Christmas)
tree 30 has been installed on thewellhead 10 h. Theproduction tree 30 may include amaster valve 31,tee 32, aswab valve 33, a cap 34 (FIG. 4C ), and aproduction choke 35.Production fluid 7 from thereservoir 6 may enter a bore of theproduction tubing 10 p, travel through the tubing bore to thesurface 5 s. Theproduction fluid 7 may continue through themaster valve 31, thetee 32, and through thechoke 35 to a flow line (not shown). Theproduction fluid 7 may continue through the flow line to a separation, treatment, and storage facility (not shown). Thereservoir 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 thesurface 5 s, apower 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, theproduction tubing string 10 p may have been installed with a dock 15 (FIG. 4A ) assembled as a part thereof and thepower cable 20 secured therealong. - The
dock 15 may receive a lander 65 (FIG. 2A ) of theESP 60 and include a subsurface safety valve (SSV) 3, one ormore sensors 4 u,b, a part, such as one ormore followers 13, of an auto-orienter, apenetrator 14, a part, such as one ormore 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 thereservoir 6 to thewellhead 10 h 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 acontrol line 11 extending along an outer surface of theproduction tubing 10 p to thewellhead 10 h. 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 4 u,b may be a pressure or pressure and temperature (PT) sensor. Thesensors 4 u,b may be located along theproduction tubing 10 p so that theupper sensor 4 u is in fluid communication with an outlet of theESP 60 and alower sensor 4 b is in fluid communication with an inlet 80 (FIG. 2C ) of theESP 60. Thesensors 4 u,b may be in data communication with a motor controller (not shown) of thecontrol unit 39 via a data conduit of thecontrol line 11, such as an electrical or optical cable. The data conduit may also provide power for thesensors 4 u,b. - The
penetrator 14 may receive an end of thecable 20. Thecable 20 may be fastened along an outer surface of theproduction tubing 10 p at regular intervals, such as by clamps or bands (not shown). Thewet matable connector FIG. 2A ) andboxes 16 for each conductor 21 (FIG. 1B , three shown) of thecable 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 FIG. 2A ) and one ormore followers 13. As theESP 60 is lowered into thedock 15, the auto-orienter pins 66 with therespective boxes 13. Each of thelander 65 anddock 15 may further include a torque profile, such one or more splines 67 (FIG. 2A ), 18. Engagement of thesplines ESP 60 to theproduction tubing 10 p. A landing shoulder may be formed at a top of each of thesplines 18 to longitudinally support theESP 60 in theproduction tubing 10 p. - The
reservoir 6 may be live and shut-in by theclosed master valve 31,swab valve 33, and SSV 3. Alternatively, thereservoir 6 may be dead due to depletion and/or by kill fluid. Alternatively, theLARS 1 may further include a lubricator 200 (FIG. 5A ) for deploying theESP 60. Alternatively, if thedock 15,power cable 20, and controlline 11 was not installed with theproduction tubing 10 p, 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. TheLARS 1 may then not be needed for the initial installation of theESP 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 theBOPs 38,ESP 60, and runningtool 59 to the wellsite. Thewireline truck 40 may be used to remove thecap 34 from thetree 30 and install theBOPs 38 onto the tree. Thewireline truck 40 may include acontrol room 42, a generator (not shown), aframe 44, apower converter 45, awinch 47 having a deployment cable, such aswireline 50, wrapped therearound, and aboom 48. Alternatively, the deployment cable may be slickline or wire rope. Thecontrol room 42 may include acontrol console 42 c and a programmable logic controller (PLC) 42 p. The generator may be diesel-powered and may supply a one or more phase (i.e., three) alternating current (AC) power signal to thepower converter 45. Alternatively, the generator may produce a direct current (DC) power signal. Thepower 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. Thepower 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 thewireline 50 for transmission to the runningtool 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 thewinch 47 winds and unwinds the wireline. Thecontrol console 42 c 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 theframe 44 and thewireline 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. Thewireline truck 40 may further include a hydraulic power unit (HPU) 46. TheHPU 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. Thewinch 47 may include a drum having thewireline 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 theboom 48. Thewireline 50 may extend through the sheave and an end of the wireline may be fastened to a cablehead of the runningtool 59. TheHPU 46 may also be connected to theBOPs 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 theswab 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 theproduction tubing 10 p. TheBOPs 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 thewireline 50 when actuated and sealing the bore. The cable preventer may be capable of sealing against an outer surface of thewireline 50 when actuated. -
FIG. 1B illustrates thepower cable 20. Thecable 20 may include a core 27 having one or more (three shown)wires 25 and ajacket 26, and one ormore layers 29 i,o of armor. Eachwire 25 may include aconductor 21, ajacket 22, asheath 23, andbedding 24. Theconductors 21 may each be made from an electrically conductive material, such as aluminum, copper, or alloys thereof. Theconductors 21 may each be solid or stranded. Eachjacket 22 may electrically isolate arespective conductor 21 and be made from a dielectric material, such as a polymer (i.e., ethylene propylene diene monomer (EPDM)). Eachsheath 23 may be made from lubricative material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape helically wound around arespective wire jacket 22. Eachbedding 24 may serve to protect and retain therespective sheath 23 during manufacture and may be made from a polymer, such as nylon. Thecore jacket 26 may protect and bind thewires 25 and be made from a polymer, such as EPDM or nitrile rubber. - The
armor 29 i,o may be made from one ormore layers 29 i,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. Thearmor 29 i,o may include two contra-helically wound layers 29 i,o of wire, fiber, or strip. Additionally, a buffer (not shown) may be disposed between the armor layers 29 i,o. The buffer may be tape and may be made from the lubricative material. Additionally, thecable 20 may further include apressure 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, thepower cable 20 may be flat. -
FIGS. 1C and 1D illustrate thewireline 50. Thewireline 50 may include aninner core 51, aninner jacket 52, ashield 53, anouter jacket 56, and one ormore layers 57 i,o of armor. Theinner core 51 may be the first conductor and made from an electrically conductive material, such as aluminum, copper, or alloys thereof. Theinner core 51 may be solid or stranded. Theinner jacket 52 may electrically isolate the core 51 from theshield 53 and be made from a dielectric material, such as a polymer (i.e., polyethylene). Theshield 53 may serve as the second conductor and be made from the electrically conductive material. Theshield 53 may be tubular, braided, or a foil covered by a braid. Theouter jacket 56 may electrically isolate theshield 53 from thearmor 57 i,o and be made from a fluid-resistant dielectric material, such as polyethylene or polyurethane. Thearmor 57 i,o may be made from one ormore layers 57 i,o of the high strength material to support theESP 60. Thearmor 57 i,o may include two contra-helically wound layers 57 i,o of wire, fiber, or strip. - Additionally, the
wireline 50 may include asheath 55 disposed between theshield 53 and theouter jacket 56. Thesheath 55 may be made from lubricative material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape helically wound around theshield 53. If lead is used for thesheath 55, a layer ofbedding 54 may insulate theshield 53 from the sheath and be made from the dielectric material. Additionally, abuffer 58 may be disposed between the armor layers 57 i,o. Thebuffer 58 may be tape and may be made from the lubricative material. -
FIGS. 2A-2D illustrate theESP 60. TheESP 60 may include thelander 65, anelectric motor 70, ashaft seal 75, theinlet 80, a pump having one ormore sections packoff 99.Housings 70 h-95 h of each of the ESP components may be longitudinally and torsionally connected, such as byflanged connections flanged connections 90 u,b may be replaced by theflanged connections 61.Shafts 70 s-95 s of themotor 70,shaft seal 75,inlet 80, and pumpsections shaft couplings 63. Alternatively, thehousings 70 h-95 h may be connected by threaded connections. - The
motor 70 may be filled with a dielectric, thermally conductive liquid lubricant, such as motor oil. Themotor 70 may be cooled by thermal communication with theproduction fluid 7. Themotor 70 may include a thrust bearing (not shown) for supporting thedrive shaft 70 s. In operation, themotor 70 may rotate thedrive shaft 70 s, thereby driving thepump shafts pump drive shaft 70 s may be directly drive thepump shaft - 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, theESP 60 may include a second (or more) motor for tandem operation with themotor 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 thereservoir fluid 7 being pumped through thepump motor 70 by equalizing the lubricant pressure with the pressure of thereservoir fluid 7. Theshaft seal 75 may house a thrust bearing (not shown) capable of supporting thrust load from thepump 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 theproduction fluid 7. The standard type inlet may include a plurality ofports 81 allowingreservoir fluid 7 to enter a lower orfirst section 85 of thepump reservoir fluid 7. The static gas separator type may include a reverse-flow path to separate a gas portion of thereservoir fluid 7 from a liquid portion of the reservoir fluid. - The
packoff 99 may have one or more fixed seals received by thepolished bore receptacle 17 of thedock 15, thereby isolating discharge ports (not shown) of thepackoff 99 from thepump inlet 80. Thepackoff 99 may further include a latch (not shown) operable to engage a latch profile (not shown) of thedock 15, thereby longitudinally connecting theESP 60 to theproduction tubing 10 p. Thepackoff 99 may further include an inner profile for engagement with the runningtool 59. Additionally, thepackoff 99 may include a bypass vent (not shown) for releasing gas separated by thepump inlet 80 that may collect below the packoff and preventing gas lock of thepump - The
pump section respective pump shaft reservoir fluid 7 and flow through the stationary diffuser may convert a portion of the velocity into pressure. Thepump pressurized reservoir fluid 7 to the packoff bore. - Alternatively, the
pump 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 thesensors 4 u,b. The sensor sub may include a controller, a modem, a diplexer, and one or more sensors (not shown) distributed throughout theESP 60. The controller may transmit data from the sensors to the motor controller viaconductors 21 of thecable 20. Alternatively, thecable 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 thereservoir fluid 7 entering thepump inlet 80. A GOR sensor may also be in fluid communication with thereservoir fluid 7 entering thepump inlet 80. A second PT sensor may be in fluid communication with thereservoir 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 themotor 70 is being sufficiently cooled. A voltage meter and current (VAMP) sensor may be in electrical communication with thecable 20 to monitor power loss from the cable. Further, one or more vibration sensors may monitor operation of themotor 70, thepump shaft seal 75. A flow meter may be in fluid communication with the pump outlet for monitoring a flow rate of thepump tree 30 may include a flow meter (not shown) for measuring a flow rate of thepump - 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 themotor 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 themotor 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 thecable injector 100 in an open or partially open position.FIG. 3B illustrates thecable injector 100 in a closed position. Thecable injector 100 may include atraction assembly 101, adrive motor 102, and aframe 103. Thetraction assembly 101 may include one or more segments, such as astationary segment 101 d and amovable segment 101 p. Thestationary segment 101 d may be connected to a base 103 b of theframe 103, such as by one or more fasteners (not shown). Theframe 103 may further include a coupling, such as aflange 103 f, connected to the base 103 b, such as by one or more fasteners or a weld. Theflange 103 f may mate with a corresponding upper flange of theBOPs 38 and be connected thereto by one or more fasteners. Alternatively, the coupling may be threaded or quick-connect. Theframe 103 may further have a passage, such aslit 115 formed through walls of theflange 103 f andbase 103 b for receiving thewireline 50. - Each
segment 101 d,p may include a respective:body 105 d,p,conveyor 106 d,p,tensioner 107 p (stationary tensioner not shown), and counter bearing 116 d,p. Eachbody 105 d,p may be rectangular and have a cavity formed therein. Eachbody 105 d,p may have an open inner face for operation of therespective conveyor 106 d,p and open upper and lower ends for assembly thereof. The upper and lower ends may be closed with end caps (not shown). Eachbody 105 d,p may have a respective coupling, such as ahinge knuckle 117 p,d, formed at each inner end thereof. Themovable segment 101 p may initially be connected to thestationary segment 101 d, such as pivoted, by meshing a first mating pair of theknuckles 117 p,d and inserting ahinge pin 104 a through the meshed first pair such that the movable segment may swing between the open and closed positions. Themovable segment 101 p may then be closed by meshing a second mating pair of theknuckles 117 p,d and inserting alatch pin 104 b through the meshed second pair. The open position may be utilized for receiving thewireline 50 and the closed position may be utilized for lowering and/or driving the wireline into thewellbore 5 w. - Each
conveyor 106 d,p may include a respective: track, such as abelt 108 d,p,gear 109 d,p,idler sprocket 110 d,p,drive sprocket 111 d,p, idler hub (not shown),drive hub 112 d,p, and set 113 d,p ofgrippers 113. Alternatively, the tracks may be roller chains. Eachgripper 113 may be fastened to therespective belt 108 d,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 113 d,p may includegrippers 113 spaced along an outside of therespective belt 108 d,p at regular intervals. Eachgripper 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 eachgripper 113 may have a central recess for receiving thewireline 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 thecable injector 100. The upper and lower portions of eachgripper 113 may taper toward the belt going away from the mid portion. A nominal width of each recess may correspond to a diameter of thewireline 50. - Each set 113 d,p of
grippers 113 may engage a fraction of an outer surface of thewireline 50. In the illustrated case of twosets 113 d,p, each set may engage one-half of the wireline outer surface. Alternatively, thetraction 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 thegripper 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 57 o. A receiver opening may also be formed through each central portion for receiving acog 114 p,d of therespective sprockets 110 p,d, 111 p,d. A corresponding passage may be formed through the belt adjacent each receiver opening for passage of thecog 114 p,d therethrough. A length of each gripper and the interval between adjacent grippers may correspond to a pitch of therespective sprockets 110 p,d, 111 p,d. Each receiver opening may be shaped to mesh with thecog 114 p,d such that the gripper 113 (and belt) seats onto the adjacent bottom lands of thesprocket 110 p,d, 111 p,d, thereby transmitting driving torque/force directly from the cog to thegripper 113. Thegripper 113 may then transmit the driving force to therespective belt 108 d,p via the fasteners. - Each
belt 108 d,p may be endless and loop around and between therespective sprockets 110 p,d, 111 p,d. Eachbelt 108 d,p may have a flat or trapezoidal cross-section. Eachbelt 108 d,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. Eachbelt 108 d,p may have a length sufficient to distribute clamping force along thewireline 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 57 o. - Each
hub 112 d,p may be mounted to therespective body 105 d,p by bearings (not shown) such that the hub may rotate relative to the body while being longitudinally and transversely supported by the body. Eachsprocket 110 p,d, 111 p,d may be disposed on arespective hub 112 d,p and torsionally connected thereto, such as by interference fit or fastener. Eachgear 109 d,p may be disposed on arespective drive hub 112 d,p and torsionally connected thereto, such as by interference fit or fastener. Thestationary drive hub 112 d may also have a shaft coupling (not shown) for receiving a shaft coupling (not shown) of adrive shaft 102 d of themotor 102, thereby torsionally connecting the drive hub to the drive shaft. Thegears 109 d,p may be configured to mesh upon closing of thecable injector 100, thereby torsionally connecting thestationary drive hub 112 d to themovable drive hub 112 p. - The
drive motor 102 may be hydraulic and bidirectional such that thecable injector 100 may be used to push thewireline 50 into thewellbore 5 w and pull the wireline from the wellbore. Thedrive motor 102 may have ahousing 102 h connected to abracket 103 t of theframe 103, such as by one or more fasteners (not shown). An inlet and outlet of the drive motor may be in fluid communication with theHPU 46 via flexible conduits, such ashoses 41 a,b. Thedrive 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 thehousing 102 h. The rotor may be torsionally connected to thedrive shaft 102 d. Thedrive 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 thehousing 102 h 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 themotor 102 may have an additional hydraulic port for supplying the actuator. Alternatively, themotor 102 may be electric or pneumatic. - Each
tensioner 107 p 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. Eachtensioner 107 p may be in fluid communication with theHPU 46 via a flexible conduit, such as a hose 43 (common or individual). Eachtensioner 107 p may be operated to extend the roller into engagement with therespective belt 108 d,p, thereby tightening therespective belt 108 d,p and gripper set 113 d,p into engagement with therespective sprockets 110 p,d, 111 p,d. Each counter bearing 116 p may include a base connected to therespective body 105 d,p and one or more rollers mounted along the base for rotation relative thereto. As each tensioner 107 p tightens therespective belt 108 d,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, thecable injector 100 may be configured to inject a workstring, such as coiled tubing or continuous sucker rod. -
FIGS. 4A and 4B illustrate insertion of theESP 60 into thewellbore 5 w using theLARS 1.FIG. 4C illustrates operation of theESP 60. Referring specifically toFIG. 4A , thetree valves ESP 60 and runningtool 59 may be assembled, lowered, and suspended in thetree 30,wellhead 10 h, and/or upper portion of thewellbore 5 w by thewinch 47. The runningtool 59 may include an electrically operated gripper for connecting to thepackoff 99. - The
cable injector 100 may then be connected to theBOPs 38. Thecable injector 100 may be connected with themovable segment 101 p in the open position or without the movable segment. If connected without themovable segment 101 p, themovable segment 101 p may then be connected to thestationary segment 101 d in the open position. Themovable segment 101 p may then be closed and secured around thewireline 50. Thehoses 41 a,b and 43 may then be connected to thecable injector 100. Thetensioners 107 p may then be operated to engage therespective belts 108 d,p with thesprockets 110 d,p, 111 d,p. Thewinch 47 may be idled and thedrive motor 102 may then be operated to lower theESP 60 into thewellbore 5 w using thewireline 50 until thelander 65 is proximate thedock follower 13. Should lowering of theESP 60 become obstructed, such as by deviations in theproduction tubing 10 p, thecable injector 100 may push thewireline 50 into thewellbore 5 w. - Alternatively, the
body 105 d 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 , theESP 60 may be slowly lowered while thefollower 13 engages thecam 69 and rotates theESP 60 relative to theproduction tubing 10 p to align the wet-matable connector FIG. 4C , lowering of theESP 60 may continue to engage the wet-matable connector PBR 17. The packoff latch may be set. The running tool gripper may be operated using thewireline 50 to release theESP 60 from the runningtool 59. Operation of thecable injector 100 may then be reversed to retrieve thewireline 50 and runningtool 59 from thewellbore 5 w. Thecable injector 100, runningtool 59, andBOPs 38 may be removed from theproduction tree 30. Thecap 34 may be connected to theproduction tree 30. The SSV 3 may be opened and theESP 60 operated to pumpproduction fluid 7 from thewellbore 5 w. Retrieval of theESP 60 for service or replacement may be accomplished by reversing the insertion method. -
FIG. 5A illustrates alubricator 200 and thecable injector 100 connected thereto for use with theLARS 1, according to another embodiment of the present disclosure. Thelubricator 200 may include a tool housing 205 (aka lubricator riser), aseal head 210, atee 215, and ashutoff valve 220. The lubricator components may be connected, such as by flanged connections. Thetee 215 may also have a lower flange for connecting to the upper BOP flange. Thecable injector 100 may connect to an upper flange of theseal head 210. Theseal head 210 may include one ormore stuffing boxes 225 u,b and agrease injector 230. Eachstuffing box 225 u,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 theHPU 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 thewireline 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 thewireline 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 analternative PCA 240 for use with theLARS 1, according to another embodiment of the present disclosure. A more detailed discussion regarding use of thelubricator 200 andPCA 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. ThePCA 240 may include one ormore clamps 241 u,b, adriver 250, one or more blow out preventers (BOPs) 38, 265 and ashutoff 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 theproduction tubing 10 p. - Each
clamp 241 u,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 theHPU 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 thePLC 42 p 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 theESP 60, thereby longitudinally connecting the ESP to thePCA 240. Engagement of the bands may be detected by operation of the contact switches. Eachclamp 241 u,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, theshutoff valve 262 may include an actuator (not shown), such as a hydraulic actuator connected to theHPU 46 by a flexible conduit. Theannular BOP 265 may include a housing, a piston, and an annular packing. Theannular 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 theESP 60 extending longitudinally through the housing. - The
driver 250 may include one or more (two shown) units. Thedriver 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 theHPU 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 theHPU 46. The data cable may be connected to thePLC 42 p 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 withrespective 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 thecontrol console 42 c to facilitate engagement of the sockets with thebolts 91. The arm assemblies may be moved until the sockets engage thebolts 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 90 u,b may include anupper flange 90 u connected to thepump section housing 95 h, such as by a weld or a threaded connection, and alower flange 90 b connected to thepump section housing 95 h, such as by a weld or a threaded connection. Theflanged connection 90 u,b, may include anauto orienting profile 92 having mating portions formed in eachflange 90 u,b. Theupper flange 90 u may have passages formed therethrough for receiving one or more threaded fasteners, such as thebolts 91. The passage may receive a shaft of eachbolt 91 and a head of the bolt may engage an upper surface of theflange 90 u when the shaft is inserted through the passage. A lower end of thesection housing 95 h may serve as a trap for thebolts 91, thereby preventing escape of thebolts 91 during insertion of the section housing into thePCA 240. To trap thebolts 91, the bolts may be disposed in the passages before theupper flange 90 u is connected to the section housing 135 h. Thelower flange 90 b may have threadedsockets 93 for receiving threaded shafts ofrespective bolts 91, thereby forming theflanged connection 90 u,b. The passages andsockets 93 may be equally spaced around therespective flanges 90 u,b at a predetermined increment, such as ninety degrees for four, sixty degrees for six, or forty-five degrees for eight. - The
flanged connection 90 u,b may further include a temporary connection for eachflange 90 u,b, such asshearable fasteners 94. One of theshearable fasteners 94 may torsionally connect theupper shaft coupling 93 of thefirst pump section 95 to thelower flange 90 b and another one of theshearable fasteners 94 may torsionally connect theupper shaft coupling 93 of thesecond pump section 95 to theupper flange 90 u. Theshaft couplings 93 may be temporarily fastened in mating positions such that when the auto-orienting profile aligns theflanges 90 u,b, theshaft couplings 93 may also be aligned. Theshearable fasteners 94 may fracture in response to operation of themotor 70 once theESP 60 has landed in thedock 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 themotor 70 and thelander 65. The second deployment section may include theshaft seal 75. The third deployment section may include theinlet 80 and thefirst pump section 85. The fourth deployment section may include thesecond pump section 95 and thepackoff 99. A length of each deployment section (plus running tool 59) may be less than or equal to a length of the tool housing 205 h. The arrangement and number of deployment sections may vary based on parameters of theESP 60, such as number of stages and components. - The
wireline 50 may be inserted into theseal head 210 of thelubricator 200 and connected to a cablehead of the runningtool 59. The runningtool 59 may then be connected to the first deployment section. The first deployment section may be inserted into thetool housing 205. Thelubricator 200 and first deployment section may be hoisted over thePCA 240 using thewireline 50 and/or a crane (not shown). - The crane may suspend the
lubricator 200 while thewireline winch 47 is operated to lower the first deployment section until thelander 65 and a lower portion of themotor 70 are accessible. Themotor 70 may then be serviced, such as by adding motor oil thereto. Thelubricator 200 may be lowered onto thePCA 240 using the crane. Thelubricator tee 215 may then be fastened to theupper clamp 241 u, such as by a flanged connection. Theseal head 210 may be operated to engage thewireline 50. Themaster 31 andswab 33 valves may then be opened. - The first deployment section may be lowered into the
PCA 240 using thewireline 50 until themotor groove 62 is aligned with theupper clamp 241 u. Theupper clamp 241 u may then be operated to engage themotor 70, thereby supporting the first deployment section. Theannular BOP 265 may then be operated to engage the packing with an outer surface of themotor 70. Since a bottom of themotor 70 may be sealed, the first deployment section may plug a bore of thePCA 240, thereby sealing an upper portion of the PCA from wellbore pressure. The lubricator connection to thePCA 240 may be disassembled. Theupper clamp 241 u may also secure the first deployment section from being ejected from thePCA 240 due to wellbore pressure. The runningtool 59 may be operated to release the first deployment section using thewireline 50. Thelubricator 200 and runningtool 59 may then be removed. The second deployment section may be inserted into thetool housing 205 and connected to the runningtool 59. Thelubricator 200 and second deployment section may be hoisted over thePCA 240 using thewireline 50 and/or the crane. - The crane may suspend the
lubricator 200 while thewireline winch 47 is operated to lower the second deployment section until thelower flange 61 of theshaft seal 75 seats on theupper flange 61 of themotor 70. During lowering, theflanges 61 may be manually aligned and the uppermotor shaft coupling 63 may be manually aligned and engaged with the lowerseal shaft coupling 63. Theflanged connection 61 may be assembled. Thelubricator 200 may be lowered onto thePCA 240 using the crane 90. Thelubricator tee 215 may again be fastened to thePCA 240. Theseal head 210 may again be operated to engage thewireline 50. Theannular BOP 265 may be disengaged from themotor 70. Theupper clamp 241 u may be operated to release themotor 70. The first and second deployment sections may be lowered into thePCA 240 until theshaft seal groove 62 is aligned with theupper clamp 241 u. Theupper clamp 241 u may then be operated to engage theshaft seal 75, thereby supporting the first and second deployment sections. Theannular BOP 265 may then be operated to engage an outer surface of theshaft seal 75. - The lubricator connection to the
PCA 240 may be disassembled. The runningtool 59 may be operated to release the second deployment section using thewireline 50. Thelubricator 200 and runningtool 59 may then be removed. The third deployment section may be inserted into thetool housing 205 and connected to the runningtool 59. Thelubricator 200 and third deployment section may be hoisted over thePCA 240 using thewireline 80 and/or the crane. The crane may suspend thelubricator 200 while thewireline winch 47 is operated to lower the third deployment section until the lower firstpump section flange 61 seats on the uppershaft seal flange 61. During lowering, theflanges 61 may be manually aligned and the upperseal shaft coupling 63 may be manually aligned and engaged with the lower pumpsection shaft coupling 63. Theflanged connection 101 may be assembled. Thelubricator 200 may be lowered onto thePCA 240 using the crane 90. Thelubricator tee 215 may again be fastened to thePCA 240. Theseal head 210 may again be operated to engage thewireline 50. Theannular BOP 265 may be disengaged from theshaft seal 75. Theupper clamp 241 u may be operated to release theshaft seal 75. The first, second, and third deployment sections may be lowered into thePCA 240 until the firstpump section groove 62 is aligned with thelower clamp 241 b. Thelower clamp 241 b may then be operated to engage thefirst 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 runningtool 59 may be operated to release the third deployment section using thewireline 50. The runningtool 59 may be raised from thePCA 240 into thelubricator 200 using thewireline 50. Theisolation valve 262 may be closed. The lubricator connection to thePCA 240 may be disassembled. Thelubricator 200 and runningtool 59 may then be removed. The fourth deployment section may be inserted into thetool housing 205 and connected to the running tool. Thelubricator 200 and fourth deployment section may be hoisted over thePCA 240 using thewireline 50 and/or the crane. - The
lubricator 200 may be lowered onto thePCA 240 using the crane. Thelubricator tee 215 may again be fastened to thePCA 240. Theseal head 210 may again be operated to engage thewireline 50. Theisolation valve 262 may be opened. Visibility fluid may be injected into thePCA 240. The runningtool 59 and fourth deployment section may be lowered into thePCA 240 until the upper firstpump section flange 90 u is proximate to the lower secondpump section flange 90 b. The fourth deployment section may be slowly lowered to engage the parts of the auto-orientingprofile 92 for aligning theflanges 90 u,b. Once the auto-orientingprofile 92 has mated, thedriver arm assemblies 53 may be operated to engage thebolts 91. - Each driver motor may be operated to rotate the
bolts 91 intorespective sockets 93. Torque and turns may be monitored by the control room operator and/or thePLC 42 p to ensure proper assembly. Thearm assemblies 53 may be disengaged from the upper flange 130 u. Once the flanged connection 90 ub, has been fully assembled, thelower clamp 241 b may be operated to disengage the firstpump section housing 95 h. Thecable injector 100 may then be connected to a top of thelubricator 200 and closed/assembled around thewireline 50. Thecable injector 100 may then be operated to lower the assembledESP 60 into thewellbore 5 w. - Alternatively, the
tool housing 205 may have a length corresponding to a length of theESP 60, thereby obviating the need for thePCA 240. -
FIG. 6A illustrates a power cable deployedESP 360 for use with a modified LARS. The modified LARS may be similar to theLARS 1 except that the LARS truck components may be mounted on a skid frame and thepower converter 45 may output a medium voltage DC power signal to the wireline for driving theESP 360. The medium voltage power signal may be greater than or equal to one kilovolt, such as three to ten kilovolts. TheLARS PLC 42 p 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 theelectric motor 70, a power conversion module (PCM) 361, theseal section 75, theinlet 80, thepump 85, alander 363, anoutlet 364, and acablehead 365. Additionally, thepump 85 may be a first pump section and theESP 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. Thecablehead 365 may include a cable fastener (not shown), such as slips or a clamp for longitudinally connecting theESP 360 to thewireline 50. - The
wireline 50 may be longitudinally coupled to thecablehead 365 by a shearable connection (not shown). Thewireline 50 may be sufficiently strong so that a margin exists between the deployment weight and the strength thereof. Thecablehead 365 may further include a fishneck so that if theESP 360 become trapped in thewellbore 5 w, such as by buildup of sand, thewireline 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 theESP 360. - The
cablehead 365 may also include leads extending therethrough. The leads may provide electrical communication between the conductors of thewireline 50 and thePCM 361. ThePCM 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 thecontrol 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 thereservoir fluid 7 entering theinlet 80. A gas to oil ratio (GOR) sensor may also be in fluid communication with thereservoir fluid 7 entering theinlet 80. A second PT sensor may be in fluid communication with thereservoir fluid 35 discharged from theoutlet 364. A temperature sensor (or PT sensor) may be in fluid communication with the lubricant to ensure that themotor 70 andPCM 361 are being sufficiently cooled. Multiple temperature sensors may also be included in thePCM 361 for monitoring and recording temperatures of the various electronic components. A voltage meter and current (VAMP) sensor may be in electrical communication with thewireline 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 themotor 70, thepump 85, and/or theseal section 75. A flow meter may be in fluid communication with theoutlet 364 for monitoring a flow rate of thepump 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 thepump 85 and/ormotor 70 occurs. - In anticipation of depletion, the
production tubing string 310 p may have alanding nipple 315 installed at a lower end thereof. The landingnipple 315 may have a seal bore, a torsional coupling, such as an auto-orienting castellation, and a stop shoulder. Thelander 363 may have a tubing seal, a torsional coupling, such as an auto-orienting castellation, and a stop shoulder. Engagement of thelander 363 with the landingnipple 315 may engage the tubing seal with the seal bore, align the castellations, and engage the stop shoulders, thereby longitudinally supporting theESP 360 from theproduction tubing string 310 p and torsionally connecting the ESP to the production tubing string, and isolating the inlet 64 i from the outlet 640. - Alternatively, the
ESP 360 may include an isolation device having an anchor and a packer instead of thelander 363. -
FIG. 6B illustrates insertion of theESP 360 into thewellbore 5 w using thecable injector 100, according to another embodiment of the present disclosure.FIG. 6C illustrates operation of the power cable deployedESP 360. Referring specifically toFIG. 6B , thetree valves ESP 360, runningtool 59 andseal head 210 may be assembled, theseal head 210 may be connected to thetree 30, and the ESP and running tool may be lowered and suspended in thetree 30,wellhead 10 h, and/or upper portion of thewellbore 5 w by thewinch 47. Thecable injector 100 may then be connected to a top of theseal head 210 and closed/assembled around thewireline 50. Thecable injector 100 may then be operated to lower theESP 360 into thewellbore 5 w using thewireline 50 until themotor 70 is adjacent to the SSV 3. - Referring specifically to
FIG. 6C , theseal head 210 may then be operated to engage thewireline 50 and the SSV 3 opened. Thecable injector 100 may then continue to lower theESP 360 to the deployment depth. Once thelander 363 has engaged thelanding nipple 315, thecable injector 100 may be disassembled and disconnected from theseal head 210. TheESP 360 may then be operated to pumpproduction fluid 7 from thewellbore 5 w. - Alternatively, the seal head may be operated to engage the wireline before lowering the
ESP 360 into the wellbore. Alternatively, the rest of thelubricator 200 may be used to assemble, insert, and/or deploy theESP 360, as discussed above for theESP 60. -
FIGS. 7A-7D illustrate insertion of the power cable deployedESP 360 into thewellbore 5 w using thecable injector 100, according to another embodiment of the present disclosure.FIG. 7E illustrates operation of the power cable deployedESP 360. Referring specifically toFIG. 7A , thetree valves ESP 360, runningtool 59 and one 225 u of thestuffing boxes 225 u,b may be assembled, thestuffing box 225 u may be connected to thetree 30, and the ESP and running tool may be suspended in thetree 30 and/or upper portion of thewellbore 5 w by thewinch 47. Thecable injector 100 may then be connected to a top of thestuffing box 225 u and closed/assembled around thewireline 50. Thecable injector 100 may then be operated to lower theESP 360 into thewellbore 5 w using thewireline 50 until themotor 70 is adjacent to the SSV 3 and/or the deployment depth. - Referring specifically to
FIG. 7B , thewinch 47 may then be locked to suspend theESP 360. Thecable injector 100 may be disassembled and disconnected from theseal head 210. Amold 301 may be assembled around thewireline 50 and connected to a top of thestuffing box 225 u. A more detailed discussion regarding use of themold 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 themold 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 thesealant mixture 345. Thesealant mixture 345 may continue from the mix head into themold 301. - The
mold 301 may include asplit housing 305 and upper and lower seals (not shown). Thehousing 305 may include a pair of matingsemi-tubular segments 305 a,b. Eachhousing segment 305 a,b may have radial couplings, such asflanges 308, formed therealong and half of a longitudinal coupling (not shown), such as a flange, formed at one or both longitudinal ends thereof. Theradial flanges 308 of eachhousing segment 305 a,b may be connected to the mating radial flanges byfasteners 307, such as bolts and nuts. Agasket 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 thewireline 50, thereby forming anannulus 312 between the mold housing and the wireline. Thehousing 305 may have asprue 306 formed through a wall of one of thesegments 305 a,b and in fluid communication with theannulus 312. An inner diameter of the mold seals may be slightly less than an outer diameter of thewireline 50 so that the mold seals engage an outer surface of the wireline themold 301 is assembled. - Referring specifically to
FIG. 7C , thesealant 345 may be a polymer, such as an elastomer or thermoplastic elastomer. Once themold 301 has been assembled around thewireline 50, the mix head may be lifted to themold 301 by the service truck crane or the service truck platform may lift the reaction injector to themold 301. The mix head may be connected to thesprue 306. The supply pumps may then be operated to pump the liquid reactants to the mix head. Thesealant mixture 345 may continue from the mix head into themold 301. Air displaced by thesealant mixture 345 may vent from the mold via leakage through and along thearmor 57 i,o. Thesealant mixture 345 may flow around and along theannulus 312 until thesealant mixture 345 encounters the seals. Pressure in themold 301 may increase and thesealant mixture 345 may be forced into thearmor 57 i,o. Sealant penetration into thewireline 50 may be stopped by theouter jacket 56. Pumping of thesealant mixture 345 may continue until themold 301 is filled. Themold 301 may be heated by exothermic polymerization of themixture 345. A melting temperature of the mold seals,gasket 309, andouter jacket 56 may be suitable to withstand the exothermic reaction. - Referring specifically to
FIG. 7D , once thesealant 345 has cured and cooled to at least a point sufficient to maintain structural integrity, the mix head may be disconnected from themold 301 and themold 301 may be disconnected from thestuffing box 225 u. Thefasteners 307 may then be removed. The service truck may further include a hydraulic spreader. The spreader may be connected to themold 301 and operated to separate the mold. The service truck may stow themold 301 and mix head and leave the wellsite. A length of the sealedportion 350 may correspond to a length of a seal of thestuffing box 225 u and be substantially less than a length of thewireline 50. An outer diameter of the sealedportion 350 may be slightly greater than an outer diameter of the rest of thewireline 50. - Referring specifically to
FIG. 7D , thestuffing box 225 u may then be operated to engage thewireline 50 and the SSV 3 opened. Thewinch 47 may then be unlocked and operated to lower theESP 360 to deployment depth. Alternatively, thecable injector 100 may be reinstalled around the sealedportion 350 and operated to lower theESP 360 to deployment depth. As theESP 360 is lowered, the sealedportion 350 may be lowered into alignment with the stuffing box seal as thelander 363 engages with the landingnipple 315. TheESP 360 may then be operated to pumpproduction fluid 7 from thewellbore 5 w. - 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 (25)
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.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
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US14/049,420 US20140102721A1 (en) | 2012-10-11 | 2013-10-09 | Cable injector for deploying artificial lift system |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US201261712500P | 2012-10-11 | 2012-10-11 | |
US14/049,420 US20140102721A1 (en) | 2012-10-11 | 2013-10-09 | Cable injector for deploying artificial lift system |
Publications (1)
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US20140102721A1 true US20140102721A1 (en) | 2014-04-17 |
Family
ID=49485817
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US14/049,420 Abandoned US20140102721A1 (en) | 2012-10-11 | 2013-10-09 | Cable injector for deploying artificial lift system |
Country Status (5)
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US (1) | US20140102721A1 (en) |
BR (1) | BR112015008108A2 (en) |
CA (1) | CA2887192A1 (en) |
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WO (1) | WO2014059179A2 (en) |
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Also Published As
Publication number | Publication date |
---|---|
WO2014059179A3 (en) | 2014-11-27 |
GB201507532D0 (en) | 2015-06-17 |
CA2887192A1 (en) | 2014-04-17 |
GB2526939A (en) | 2015-12-09 |
WO2014059179A2 (en) | 2014-04-17 |
BR112015008108A2 (en) | 2017-07-04 |
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