Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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CABLE INJECTOR FOR DEPLOYING ARTIFICIAL LIFT SYSTEM
CROSS-REFERENCE TO RELATED APPLICATIONS
[0ool] This application claims benefit of United States provisional patent
application
serial number 61/712,500, filed October 11,2012, which is herein incorporated
by
reference.
BACKGROUND OF THE DISCLOSURE
Field of the Disclosure
[0002] Embodiments of the present disclosure generally relate to a cable
injector
for deploying an artificial lift system.
Description of the Related Art
[0003] The oil industry has utilized electric submersible pumps (ESPs)
to produce
high flow-rate wells for decades, the materials and design of these pumps has
increased the ability of the system to survive for longer periods of time
without
intervention. These systems are typically deployed on the tubing string with
the power
cable fastened to the tubing by mechanical devices such as metal bands or
metal
cable protectors. Well intervention to replace the equipment requires the
operator to
pull the tubing string and power cable requiring a well servicing rig and
special
spooler to spool the cable safely. The industry has tried to find viable
alternatives to
this deployment method especially in offshore and remote locations where the
cost
increases significantly. There has been limited deployment of cable inserted
in coil
tubing where the coiled tubing is utilized to support the weight of the
equipment and
cable. Although this system is seen as an improvement over jointed tubing, the
cost,
reliability and availability of coiled tubing units have prohibited use on a
broader basis.
SUMMARY OF THE DISCLOSURE
[0004] 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
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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.
[0005] In another embodiment, a method of deploying a downhole tool into
a
wellbore includes: connecting the downhole tool to a cable; lowering the
downhole
tool into a pressure control assembly (PCA) and wellhead adjacent to the
wellbore
using the cable; after lowering the downhole tool, connecting a cable injector
to the
PCA and closing the cable injector around the cable; and operating the cable
injector,
thereby injecting the cable into the wellbore and lowering the downhole tool
to a
deployment depth in the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] 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.
[0007] Figure 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. Figure 1B illustrates a power cable of the ALS. Figure 10 and 1D
illustrate a wireline of the ALS.
[0008] Figures 2A-2D illustrate an electric submersible pump (ESP) of the
ALS.
[0009] Figures 3A, 30, and 3D illustrate a cable injector of the LARS in
an open or
partially open position. Figure 3B illustrates the cable injector in a closed
position.
[0010] Figures 4A and 4B illustrate insertion of the ESP into a wellbore
using the
LARS. Figure 40 illustrates operation of the ESP.
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[0011] Figure 5A illustrates a lubricator and the cable injector
connected thereto
for use with the LARS, according to another embodiment of the present
disclosure.
Figure 5B illustrates an alternative pressure control assembly (PCA) for use
with the
LARS, according to another embodiment of the present disclosure.
[0012] Figure 6A illustrates a power cable deployed ESP for use with a
modified
LARS. Figure 6B illustrates insertion of the power cable deployed ESP into the
wellbore using the cable injector, according to another embodiment of the
present
disclosure. Figure 60 illustrates operation of the power cable deployed ESP.
[0013] Figures 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. Figure 7E illustrates operation of the power cable deployed ESP.
[0014] Figure 8A illustrates an alternative cable injector for the LARS.
Figure 8B
illustrates a portion of another alternative cable injector for the LARS.
DETAILED DESCRIPTION
[0015] Figure 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 (B0P5) 38,
one or more running tools 59 (Figure 4A), and a cable injector 100 (Figure
3A).
[0016] A wellbore 5w has been drilled from a surface 5s of the earth into a
hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir 6 (Figure
4A). A
string of casing 10c has been run into the wellbore 5w and set therein with
cement
(not shown). The casing 10c has been perforated 9 (Figure 4B) to provide to
provide
fluid communication between the reservoir 6 and a bore of the casing 10c. A
wellhead 10h has been mounted on an end of the casing string 10c. A string of
production tubing 10p extends from the wellhead 10h to the reservoir 6 to
transport
production fluid 7 (Figure 40) from the reservoir 6 to the surface 5s. A
packer 8
(Figure 4A) has been set between the production tubing 10p and the casing 10c
to
isolate an annulus 10a (Figure 4B) formed between the production tubing and
the
casing from production fluid 7.
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[0017] A production (aka Christmas) tree 30 has been installed on the
wellhead
10h. The production tree 30 may include a master valve 31, tee 32, a swab
valve 33,
a cap 34 (Figure 4C), and a production choke 35. Production fluid 7 from the
reservoir 6 may enter a bore of the production tubing 10p, travel through the
tubing
bore to the surface 5s. The production fluid 7 may continue through the master
valve
31, the tee 32, and through the choke 35 to a flow line (not shown). The
production
fluid 7 may continue through the flow line to a separation, treatment, and
storage
facility (not shown). The reservoir 6 may initially be naturally producing and
may
deplete over time to require an artificial lift system (ALS) to maintain
production. The
ALS may include a control unit 39 (Figure 4C) located at the surface 5s, a
power
cable 20, and a downhole assembly, such as an electrical submersible pump
(ESP)
60 (Figures 2A-2D). Alternatively, the downhole assembly may include an
electrical
submersible compressor. In anticipation of depletion, the production tubing
string 10p
may have been installed with a dock 15 (Figure 4A) assembled as a part thereof
and
the power cable 20 secured therealong.
[0018] The dock 15 may receive a lander 65 (Figure 2A) of the ESP 60 and
include a subsurface safety valve (SSV) 3, one or more sensors 4u,b, a part,
such as
one or more followers 13, of an auto-orienter, a penetrator 14, a part, such
as one or
more boxes 16, of a wet matable connector, a polished bore receptacle (PBR)
17,
and a torque profile. The SSV 3 may include a housing, a valve member, a
biasing
member, and an actuator. The valve member may be a flapper operable between an
open position and a closed position. The flapper may allow flow through the
housing/production tubing bore in the open position and seal the
housing/production
tubing bore in the closed position. The flapper may operate as a check valve
in the
closed position i.e., preventing flow from the reservoir 6 to the wellhead 10h
but
allowing flow from the wellhead to the reservoir. Alternatively, the SSV 3 may
be
bidirectional. The actuator may be hydraulic and include a flow tube for
engaging the
flapper and forcing the flapper to the open position. The flow tube may also
be a
piston in communication with a hydraulic conduit of a control line 11
extending along
an outer surface of the production tubing 10p to the wellhead 10h. Injection
of
hydraulic fluid into the hydraulic conduit may move the flow tube against the
biasing
member (i.e., spring), thereby opening the flapper. The SSV 3 may also include
a
spring biasing the flapper toward the closed position. Relief of hydraulic
pressure
from the conduit may allow the springs to close the flapper.
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[0019] Each sensor 4u,b may be a pressure or pressure and temperature
(PT)
sensor. The sensors 4u,b may be located along the production tubing 10p so
that the
upper sensor 4u is in fluid communication with an outlet of the ESP 60 and a
lower
sensor 4b is in fluid communication with an inlet 80 (Figure 20) of the ESP
60. The
sensors 4u,b may be in data communication with a motor controller (not shown)
of the
control unit 39 via a data conduit of the control line 11, such as an
electrical or optical
cable. The data conduit may also provide power for the sensors 4u,b.
[0020] The penetrator 14 may receive an end of the cable 20. The cable
20 may
be fastened along an outer surface of the production tubing 10p at regular
intervals,
such as by clamps or bands (not shown). The wet matable connector 16, 66 may
include a pair of pins 66 (Figure 2A) and boxes 16 for each conductor 21
(Figure 1 B,
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.
[0021] The auto-orienter 13, 69 may include a cam 69 (Figure 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 (Figure 2A), 18. Engagement of the splines 67, 18 may torsionally connect
the
ESP 60 to the production tubing 10p. A landing shoulder may be formed at a top
of
each of the splines 18 to longitudinally support the ESP 60 in the production
tubing
10p.
[0022] The reservoir 6 may be live and shut-in by the closed master
valve 31,
swab valve 33, and SSV 3. Alternatively, the reservoir 6 may be dead due to
depletion and/or by kill fluid. Alternatively, the LARS 1 may further include
a lubricator
200 (Figure 5A) for deploying the ESP 60. Alternatively, if the dock 15, power
cable
20, and control line 11 was not installed with the production tubing 10p, a
workover rig
(not shown) may be used to remove the production tubing, install the dock,
power
cable, and control line, and reinstall the production tubing. The LARS 1 may
then not
be needed for the initial installation of the ESP 60 but may be used for later
servicing
of the ESP.
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[0023] The wireline truck 40 may be deployed to the wellsite. One or
more
delivery trucks (not shown) may transport the BOPs 38, ESP 60, and running
tool 59
to the wellsite. The wireline truck 40 may be used to remove the cap 34 from
the tree
30 and install the BOPs 38 onto the tree. The wireline truck 40 may include a
control
room 42, a generator (not shown), a frame 44, a power converter 45, a winch 47
having a deployment cable, such as wireline 50, wrapped therearound, and a
boom
48. Alternatively, the deployment cable may be slickline or wire rope. The
control
room 42 may include a control console 42c and a programmable logic controller
(PLC) 42p. The generator may be diesel-powered and may supply a one or more
phase (i.e., three) alternating current (AC) power signal to the power
converter 45.
Alternatively, the generator may produce a direct current (DC) power signal.
The
power converter 45 may include a one or more (i.e., three) phase transformer
for
stepping the voltage of the AC power signal supplied by the generator from a
low
voltage signal to an ultra low voltage signal. The power converter 45 may
further
include a one or more (i.e., three) phase rectifier for converting the ultra
low voltage
AC signal supplied by the transformer to an ultra low voltage direct current
(DC)
power signal. The rectifier may supply the ultra low voltage DC power signal
to the
wireline 50 for transmission to the running tool 59.
[0024] The rectifier may be in electrical communication with the
wireline 50 via an
electrical coupling (not shown), such as brushes or slip rings, to allow power
and data
transmission through the wireline while the winch 47 winds and unwinds the
wireline.
The control console 42c may include one or more input devices, such as a
keyboard
and mouse or trackpad, and one or more video monitors. Alternatively, a
touchscreen
may be used instead of the monitor and input devices.
[0025] 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
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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.
[0026] The BOPs 38 may include a housing having a connector, such as a
flange,
formed at each longitudinal end thereof. A lower of the BOP flanges may be
connected to an upper flange of the swab valve 33 by fasteners (not shown),
such as
bolts or studs and nuts. The BOPs housing may have a bore therethrough
corresponding to a bore of the production tubing 10p. The BOPs 38 may include
one
or more ram preventers, such as a blind ram preventer and a cable ram
preventer.
The blind ram preventer may be capable of cutting the wireline 50 when
actuated and
sealing the bore. The cable preventer may be capable of sealing against an
outer
surface of the wireline 50 when actuated.
[0027] Figure 1B illustrates the power cable 20. The cable 20 may include a
core
27 having one or more (three shown) wires 25 and a jacket 26, and one or more
layers 29i,o of armor. Each wire 25 may include a conductor 21, a jacket 22, a
sheath
23, and bedding 24. The conductors 21 may each be made from an electrically
conductive material, such as aluminum, copper, or alloys thereof. The
conductors 21
may each be solid or stranded. Each jacket 22 may electrically isolate a
respective
conductor 21 and be made from a dielectric material, such as a polymer (i.e.,
ethylene
propylene diene monomer (EPDM)). Each sheath 23 may be made from lubricative
material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape
helically
wound around a respective wire jacket 22. Each bedding 24 may serve to protect
and
retain the respective sheath 23 during manufacture and may be made from a
polymer, such as nylon. The core jacket 26 may protect and bind the wires 25
and be
made from a polymer, such as EPDM or nitrile rubber.
[0028] The armor 29i,o may be made from one or more layers 29i,o of high
strength material (i.e., tensile strength greater than or equal to one
hundred, one fifty,
or two hundred kpsi). The high strength material may be a metal or alloy and
corrosion resistant, such as galvanized steel, aluminum, or a polymer, such as
a
para-aramid fiber. The armor 29i,o may include two contra-helically wound
layers
29i,o of wire, fiber, or strip. Additionally, a buffer (not shown) may be
disposed
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between the armor layers 29i,o. The buffer may be tape and may be made from
the
lubricative material. Additionally, the cable 20 may further include a
pressure
containment layer 28 made from a material having sufficient strength to
contain radial
thermal expansion of the core 27 and wound to allow longitudinal expansion
thereof.
Alternatively, the power cable 20 may be flat.
[0029] Figures 10 and 1D illustrate the wireline 50. The wireline 50 may
include
an inner core 51, an inner jacket 52, a shield 53, an outer jacket 56, and one
or more
layers 57i,o of armor. The inner core 51 may be the first conductor and made
from an
electrically conductive material, such as aluminum, copper, or alloys thereof.
The
inner core 51 may be solid or stranded. The inner jacket 52 may electrically
isolate
the core 51 from the shield 53 and be made from a dielectric material, such as
a
polymer (i.e., polyethylene). The shield 53 may serve as the second conductor
and
be made from the electrically conductive material. The shield 53 may be
tubular,
braided, or a foil covered by a braid. The outer jacket 56 may electrically
isolate the
shield 53 from the armor 57i,o and be made from a fluid-resistant dielectric
material,
such as polyethylene or polyurethane. The armor 57i,o may be made from one or
more layers 57i,o of the high strength material to support the ESP 60. The
armor
57i,o may include two contra-helically wound layers 57i,o of wire, fiber, or
strip.
[0030] Additionally, the wireline 50 may include a sheath 55 disposed
between the
shield 53 and the outer jacket 56. The sheath 55 may be made from lubricative
material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape
helically
wound around the shield 53. If lead is used for the sheath 55, a layer of
bedding 54
may insulate the shield 53 from the sheath and be made from the dielectric
material.
Additionally, a buffer 58 may be disposed between the armor layers 57i,o. The
buffer
58 may be tape and may be made from the lubricative material.
[0031] Figures 2A-2D illustrate the ESP 60. The ESP 60 may include the
lander
65, an electric motor 70, a shaft seal 75, the inlet 80, a pump having one or
more
sections 85, 95, and a packoff 99. Housings 70h-95h of each of the ESP
components
may be longitudinally and torsionally connected, such as by flanged
connections 61,
90u,b. Alternatively, the flanged connections 90u,b may be replaced by the
flanged
connections 61. Shafts 70s-95s of the motor 70, shaft seal 75, inlet 80, and
pump
sections 85, 95 may be torsionally connected, such as by shaft couplings 63.
Alternatively, the housings 70h-95h may be connected by threaded connections.
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[0032] The motor 70 may be filled with a dielectric, thermally
conductive liquid
lubricant, such as motor oil. The motor 70 may be cooled by thermal
communication
with the production fluid 7. The motor 70 may include a thrust bearing (not
shown) for
supporting the drive shaft 70s. In operation, the motor 70 may rotate the
drive shaft
70s, thereby driving the pump shafts 85s, 95s of the pump 85, 95. The drive
shaft
70s may be directly drive the pump shaft 85s, 95s (no gearbox).
[0033] The motor 70 may be an induction motor, a switched reluctance
motor
(SRM) or a permanent magnet motor, such as a brushless DC motor (BLDC).
Additionally, the ESP 60 may include a second (or more) motor for tandem
operation
with the motor 70. The induction motor may be a two-pole, three-phase,
squirrel-cage
induction type and may run at a nominal speed of thirty-five hundred rpm at
sixty Hz.
The SRM motor may include a multi-lobed rotor made from a magnetic material
and a
multi-lobed stator. Each lobe of the stator may be wound and opposing lobes
may be
connected in series to define each phase. For example, the SRM motor may be
three-phase (six stator lobes) and include a four-lobed rotor. The BLDC motor
may
be two pole and three phase. The BLDC motor may include the stator having the
three phase winding, a permanent magnet rotor, and a rotor position sensor.
The
permanent magnet rotor may be made of one or more rare earth, ceramic, or
ceramic-metallic composite (aka cermet) magnets. The rotor position sensor may
be
a Hall-effect sensor, a rotary encoder, or sensorless (i.e., measurement of
back EMF
in undriven coils by the motor controller).
[0034] 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.
[0035] 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
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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.
[0036] The packoff 99 may have one or more fixed seals received by the
polished
bore receptacle 17 of the dock 15, thereby isolating discharge ports (not
shown) of
the packoff 99 from the pump inlet 80. The packoff 99 may further include a
latch (not
shown) operable to engage a latch profile (not shown) of the dock 15, thereby
longitudinally connecting the ESP 60 to the production tubing 10p. The packoff
99
may further include an inner profile for engagement with the running tool 59.
Additionally, the packoff 99 may include a bypass vent (not shown) for
releasing gas
separated by the pump inlet 80 that may collect below the packoff and
preventing gas
lock of the pump 85, 95. A pressure relief valve (not shown) may be disposed
in the
bypass vent.
[0037] The pump 85, 95 may be centrifugal or positive displacement. The
centrifugal pump may be a radial flow or mixed axial/radial flow. The positive
displacement pump may be progressive cavity. Each section 85, 95 of the
centrifugal
pump may include one or more stages, each stage having an impeller and a
diffuser.
The impeller may be torsionally and longitudinally connected to the respective
pump
shaft 85s, 95s, such as by a key. The diffuser may be longitudinally and
torsionally
connected to a housing of the pump, such as by compression between a head and
base screwed into the housing. Rotation of the impeller may impart velocity to
the
reservoir fluid 7 and flow through the stationary diffuser may convert a
portion of the
velocity into pressure. The pump 85, 95 may deliver the pressurized reservoir
fluid 7
to the packoff bore.
[0038] Alternatively, the pump 85, 95 may include one or more sections
of a high
speed compact pump discussed and illustrated at Figures 10 and 1D of US Pat.
App.
No. 12/794,547, filed June 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,
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or more helicoidal rotor vanes, a diffuser, and one or more diffuser vanes.
The rotor
may include a shaft portion and an impeller portion. The rotor may be
supported from
the diffuser for rotation relative to the diffuser and the housing by a
hydrodynamic
radial bearing formed between an inner surface of the diffuser and an outer
surface of
the shaft portion. The rotor vanes may interweave to form a pumping cavity
therebetween. A pitch of the pumping cavity may increase from an inlet of the
stage
to an outlet of the stage. The rotor may be longitudinally and torsionally
connected to
the motor drive shaft and be rotated by operation of the motor. As the rotor
is rotated,
the production fluid 7 may be pumped along the cavity from the inlet toward
the outlet.
The annular passage may have a nozzle portion, a throat portion, and a
diffuser
portion from the inlet to the outlet of each stage, thereby forming a Venturi.
[0039] Additionally, the ESP 60 may further include a sensor sub (not
shown).
The sensor sub may be employed in addition to or instead of the sensors 4u,b.
The
sensor sub may include a controller, a modem, a diplexer, and one or more
sensors
(not shown) distributed throughout the ESP 60. The controller may transmit
data from
the sensors to the motor controller via conductors 21 of the cable 20.
Alternatively,
the cable 20 may further include a data conduit, such as data wires or optical
fiber, for
transmitting the data. A PT sensor may be in fluid communication with the
reservoir
fluid 7 entering the pump inlet 80. A GOR sensor may also be in fluid
communication
with the reservoir fluid 7 entering the pump inlet 80. A second PT sensor may
be in
fluid communication with the reservoir fluid 7 discharged from the pump
outlet/ports.
A temperature sensor (or PT sensor) may be in fluid communication with the
lubricant
to ensure that the motor 70 is being sufficiently cooled. A voltage meter and
current
(VAMP) sensor may be in electrical communication with the cable 20 to monitor
power loss from the cable. Further, one or more vibration sensors may monitor
operation of the motor 70, the pump 85, 95, and/or the shaft seal 75. A flow
meter
may be in fluid communication with the pump outlet for monitoring a flow rate
of the
pump 85, 95. Alternatively, the tree 30 may include a flow meter (not shown)
for
measuring a flow rate of the pump 85, 95 and the tree flow meter may be in
data
communication with the motor controller.
[0040] 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
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the connector 105. For the induction motor, the motor controller may be a
switchboard (i.e., logic circuit) for simple control of the motor 70 at a
nominal speed or
a variable speed drive (VSD) for complex control of the motor. The VSD
controller
may include a microprocessor for varying the motor speed to achieve an optimum
for
the given conditions. The VSD may also gradually or soft start the motor,
thereby
reducing start-up strain on the shaft and the power supply and minimizing
impact of
adverse well conditions.
[0041] 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.
[0042] Figures 3A, 30, and 3D illustrate the cable injector 100 in an
open or
partially open position. Figure 3B illustrates the cable injector 100 in a
closed
position. The cable injector 100 may include a traction assembly 101, a drive
motor
102, and a frame 103. The traction assembly 101 may include one or more
segments,
such as a stationary segment 101d and a movable segment 101p. The stationary
segment 101d may be connected to a base 103b of the frame 103, such as by one
or
more fasteners (not shown). The frame 103 may further include a coupling, such
as a
flange 103f, connected to the base 103b, such as by one or more fasteners or a
weld.
The flange 103f may mate with a corresponding upper flange of the BOPs 38 and
be
connected thereto by one or more fasteners. Alternatively, the coupling may be
threaded or quick-connect. The frame 103 may further have a passage, such a
slit
115 formed through walls of the flange 103f and base 103b for receiving the
wireline
50.
[0043] Each segment 101d,p may include a respective: body 105d,p,
conveyor
106d,p, tensioner 107p (stationary tensioner not shown), and counter bearing
116d,p.
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Each body 105d,p may be rectangular and have a cavity formed therein. Each
body
105d,p may have an open inner face for operation of the respective conveyor
106d,p
and open upper and lower ends for assembly thereof. The upper and lower ends
may
be closed with end caps (not shown). Each body 105d,p may have a respective
coupling, such as a hinge knuckle 117p,d, formed at each inner end thereof.
The
movable segment 101p may initially be connected to the stationary segment
101d,
such as pivoted, by meshing a first mating pair of the knuckles 117p,d and
inserting a
hinge pin 104a through the meshed first pair such that the movable segment may
swing between the open and closed positions. The movable segment 101p may then
be closed by meshing a second mating pair of the knuckles 117p,d and inserting
a
latch pin 104b through the meshed second pair. The open position may be
utilized for
receiving the wireline 50 and the closed position may be utilized for lowering
and/or
driving the wireline into the wellbore 5w.
[0044] Each conveyor 106d,p may include a respective: track, such as a
belt
108d,p, gear 109d,p, idler sprocket 110d,p, drive sprocket 111d,p, idler hub
(not
shown), drive hub 112d,p, and set 113d,p of grippers 113. Alternatively, the
tracks
may be roller chains. Each gripper 113 may be fastened to the respective belt
108d,p, such as by one or more fasteners (not shown) extending through
respective
holes (not shown) formed through the belt. Each hole may be counter bored or
counter sunk such that the fastener head is flush or sub-flush with an
underside of the
belt. Each set 113d,p may include grippers 113 spaced along an outside of the
respective belt 108d,p at regular intervals. Each gripper 113 may be made from
an
abrasion resistant material, such as a metal, alloy, or cermet. Each gripper
313 may
have an upper portion, a mid portion, and a lower portion. The mid portion of
each
gripper 113 may have a central recess for receiving the wireline 50 and wings
extending transversely from the recess. The wings may form a bearing surface
for
mating with wings of an opposed gripper during operation of the cable injector
100.
The upper and lower portions of each gripper 113 may taper toward the belt
going
away from the mid portion. A nominal width of each recess may correspond to a
diameter of the wireline 50.
[0045] Each set 113d,p of grippers 113 may engage a fraction of an outer
surface
of the wireline 50. In the illustrated case of two sets 113d,p, each set may
engage
one-half of the wireline outer surface. Alternatively, the traction assembly
101 may
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include a second (or more) movable segment, such as a stationary segment and
two
moveable segments (Figure 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.
[0046] Teeth may be formed in the recess for gripping the wireline 50.
Alternatively, a die having the teeth may be fastened to the gripper 113. The
teeth
may be circumferential and decrease the nominal width of the recess to be less
than
the wireline diameter such that the teeth may penetrate the outer armor 570. A
receiver opening may also be formed through each central portion for receiving
a cog
114p,d of the respective sprockets 110p,d, 111p,d. A corresponding passage may
be
formed through the belt adjacent each receiver opening for passage of the cog
114p,d
therethrough. A length of each gripper and the interval between adjacent
grippers
may correspond to a pitch of the respective sprockets 110p,d, 111p,d. Each
receiver
opening may be shaped to mesh with the cog 114p,d such that the gripper 113
(and
belt) seats onto the adjacent bottom lands of the sprocket 110p,d, 111p,d,
thereby
transmitting driving torque/force directly from the cog to the gripper 113.
The gripper
113 may then transmit the driving force to the respective belt 108d,p via the
fasteners.
[0047] Each belt 108d,p may be endless and loop around and between the
respective sprockets 110p,d, 111p,d. Each belt 108d,p may have a flat or
trapezoidal
cross-section. Each belt 108d,p may include an inner carcass made from one or
more plies bonded together using an adhesive and an outer cover encapsulating
the
carcass. The plies may each be made from natural or synthetic fibers, such as
polymer, metal/alloy, ceramic, or carbon. The cover may be made from a
flexible
material, such as an elastomer, thermoplastic elastomer, or other suitable
polymer.
Each belt 108d,p may have a length sufficient to distribute clamping force
along the
wireline 50 such that a clamping pressure does not crush the wireline. The
gripper
teeth and belt length may also be configured such that the teeth do not damage
the
outer armor layer 570.
[0048] Each hub 112d,p may be mounted to the respective body 105d,p by
bearings (not shown) such that the hub may rotate relative to the body while
being
longitudinally and transversely supported by the body. Each sprocket 110p,d,
111p,d
may be disposed on a respective hub 112d,p and torsionally connected thereto,
such
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as by interference fit or fastener. Each gear 109d,p may be disposed on a
respective
drive hub 112d,p and torsionally connected thereto, such as by interference
fit or
fastener. The stationary drive hub 112d may also have a shaft coupling (not
shown)
for receiving a shaft coupling (not shown) of a drive shaft 102d of the motor
102,
thereby torsionally connecting the drive hub to the drive shaft. The gears
109d,p may
be configured to mesh upon closing of the cable injector 100, thereby
torsionally
connecting the stationary drive hub 112d to the movable drive hub 112p.
[0049] The drive motor 102 may be hydraulic and bidirectional such that
the cable
injector 100 may be used to push the wireline 50 into the wellbore 5w and pull
the
wireline from the wellbore. The drive motor 102 may have a housing 102h
connected
to a bracket 103t of the frame 103, such as by one or more fasteners (not
shown). An
inlet and outlet of the drive motor may be in fluid communication with the HPU
46 via
flexible conduits, such as hoses 41a,b. The drive motor 102 may further
include a
rotor (not shown) mounted in the housing for rotation relative thereto by one
or more
bearings (not shown). Injection of hydraulic fluid, such as oil, into the
inlet may
torsionally drive the rotor relative to the housing 102h. The rotor may be
torsionally
connected to the drive shaft 102d. The drive motor 102 may further include a
motor
lock operable between a locked position and an unlocked position. The motor
lock
may include a clutch torsionally connecting the rotor and the housing 102h in
the
locked position and disengaging the rotor from the housing in the unlocked
position.
The clutch may be biased toward the locked position and further include an
actuator,
such as a piston, operable to move the clutch to the unlocked position in
response to
hydraulic fluid being supplied to the motor. Alternatively the motor 102 may
have an
additional hydraulic port for supplying the actuator. Alternatively, the motor
102 may
be electric or pneumatic.
[0050] Each tensioner 107p may include a piston and cylinder assembly
and a
roller. Each piston and cylinder assembly may have a first end connected to
the
respective body and a second end mounted to the roller for rotation of the
roller
relative thereto. Each tensioner 107p may be in fluid communication with the
HPU 46
via a flexible conduit, such as a hose 43 (common or individual). Each
tensioner
107p may be operated to extend the roller into engagement with the respective
belt
108d,p, thereby tightening the respective belt 108d,p and gripper set 113d,p
into
engagement with the respective sprockets 110p,d, 111p,d. Each counter bearing
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116p may include a base connected to the respective body 105d,p and one or
more
rollers mounted along the base for rotation relative thereto. As each
tensioner 107p
tightens the respective belt 108d,p, the belt may also be tightened into
engagement
with the respective counter bearing rollers, thereby supporting the belt and
keeping
the belt from bowing inwardly.
[0051] Referring to Figure 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.
[0052] Alternatively, each belt may include segments spaced apart to
form the cog
passage instead of being continuous and the grippers may link the belt
segments.
Alternatively, the cable injector 100 may be used with other types of cable,
such as
slickline or wire rope. Alternatively, the cable injector 100 may be
configured to inject
a workstring, such as coiled tubing or continuous sucker rod.
[0053] Figures 4A and 4B illustrate insertion of the ESP 60 into the
wellbore 5w
using the LARS 1. Figure 40 illustrates operation of the ESP 60. Referring
specifically to Figure 4A, the tree valves 31, 33 may be opened. The ESP 60
and
running tool 59 may be assembled, lowered, and suspended in the tree 30,
wellhead
10h, and/or upper portion of the wellbore 5w by the winch 47. The running tool
59
may include an electrically operated gripper for connecting to the packoff 99.
[0054] The cable injector 100 may then be connected to the BOPs 38. The
cable
injector 100 may be connected with the movable segment 101p in the open
position
or without the movable segment. If connected without the movable segment 101p,
the movable segment 101p may then be connected to the stationary segment 101d
in
the open position. The movable segment 101p may then be closed and secured
around the wireline 50. The hoses 41a,b and 43 may then be connected to the
cable
injector 100. The tensioners 107p may then be operated to engage the
respective
belts 108d,p with the sprockets 110d,p, 111d,p. The winch 47 may be idled and
the
drive motor 102 may then be operated to lower the ESP 60 into the wellbore 5w
using
the wireline 50 until the lander 65 is proximate the dock follower 13. Should
lowering
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of the ESP 60 become obstructed, such as by deviations in the production
tubing 10p,
the cable injector 100 may push the wireline 50 into the wellbore 5w.
[0055] Alternatively, the body 105d may have a second coupling, such as
a flange,
connected at an end opposite the base such that a second cable injector may be
connected thereto and the cable injectors operated in tandem.
[0056] Referring specifically to Figure 4B, the ESP 60 may be slowly
lowered while
the follower 13 engages the cam 69 and rotates the ESP 60 relative to the
production
tubing 10p to align the wet-matable connector 16, 66. Referring specifically
to Figure
40, lowering of the ESP 60 may continue to engage the wet-matable connector
16,
66 and to engage the packoff seal with the PBR 17. The packoff latch may be
set.
The running tool gripper may be operated using the wireline 50 to release the
ESP 60
from the running tool 59. Operation of the cable injector 100 may then be
reversed to
retrieve the wireline 50 and running tool 59 from the wellbore 5w. The cable
injector
100, running tool 59, and BOPs 38 may be removed from the production tree 30.
The
cap 34 may be connected to the production tree 30. The SSV 3 may be opened and
the ESP 60 operated to pump production fluid 7 from the wellbore 5w. Retrieval
of
the ESP 60 for service or replacement may be accomplished by reversing the
insertion method.
[0057] Figure 5A illustrates a lubricator 200 and the cable injector 100
connected
thereto for use with the LARS 1, according to another embodiment of the
present
disclosure. The lubricator 200 may include a tool housing 205 (aka lubricator
riser), a
seal head 210, a tee 215, and a shutoff valve 220. The lubricator components
may
be connected, such as by flanged connections. The tee 215 may also have a
lower
flange for connecting to the upper BOP flange. The cable injector 100 may
connect
to an upper flange of the seal head 210. The seal head 210 may include one or
more
stuffing boxes 225u,b and a grease injector 230. Each stuffing box 225u,b may
include a packing, a piston, and a housing. A port may be formed through each
stuffing box housing in communication with the piston. The port may be
connected to
the HPU 46 via a hydraulic conduit (not shown). When operated by hydraulic
fluid, the
piston may longitudinally compress the packing, thereby radially expanding the
packing inward into engagement with the wireline 50. Each stuffing box may
further
include a spring for returning the piston or the resiliency of the packing may
be
sufficient.
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[0058] 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 (Figure 60)
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.
[0059] Figure 5B illustrates an alternative PCA 240 for use with the
LARS 1,
according to another embodiment of the present disclosure. A more detailed
discussion regarding use of the lubricator 200 and PCA 240 may be found in
U.S.
Prov. App. No. 61/550,537 (Atty. Dock. No. ZEIT/0012USL), which is herein
incorporated by reference in its entirety. The PCA 240 may include one or more
clamps 241u,b, a driver 250, one or more blow out preventers (B0P5) 38, 265
and a
shutoff valve 262. Each PCA component may include a housing having a
connector,
such as a flange, formed at each longitudinal end thereof. The flanges may be
connected by fasteners (not shown), such as bolts or studs and nuts. Each PCA
housing may have a bore therethrough corresponding to a bore of the production
tubing 10p.
[0060] Each clamp 241u,b may include a housing having an annular inner
portion
and a pair of outer portions connected to the inner portion, such as by a
threaded
connection or flanges. Passages may be formed through the inner portion
corresponding to each outer portion. An arm may be disposed in each outer
portion.
Each arm may have a piston formed at an outer end thereof and a band formed at
an
inner end thereof. Each band may be U-shaped. Each arm may be radially
moveable between a disengaged position (shown) and an engaged position (not
shown). The piston may divide each outer portion into a pair of chambers. An
inner
port may be formed through a wall of the inner housing portion corresponding
to each
outer housing portion and an outer port may be formed through each outer
portion.
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Each port may be connected to the HPU 46. A proximity sensor, such as a
contact
switch, may be connected to each arm at a base of the respective band. Leads
may
connect each contact switch to the PLC 42p and may be flexible to accommodate
movement of the arms. In operation, the arms may be engaged by supplying
pressurized hydraulic fluid to the arm piston via outer ports and returning
hydraulic
fluid from the inner ports, thereby moving the arms inward in opposing
fashion. The
arms may be moved until the bands engage a corresponding profile, such as
groove
62 (Figure 2A), formed in an outer surface of the ESP 60, thereby
longitudinally
connecting the ESP to the PCA 240. Engagement of the bands may be detected by
operation of the contact switches. Each clamp 241u,b may be locked in the
engaged
position hydraulically. Disengagement of the arms may be accomplished by
reversing
the hydraulic flow.
[0061] 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.
[0062] 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
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connected to the PLC 42p and may provide data communication between one or
more sensors and the PLC.
[0063]
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.
[0064]
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
(Figure 2D) by the control room operator. The video camera may further include
one
or more lights. In operation, clear visibility fluid may be pumped into the
PCA bore.
The arms may be engaged with respective bolts 91 by supplying pressurized
hydraulic fluid to the arm pistons via ports, thereby moving the arms inward
in
opposing fashion.
The arm assemblies may be moved synchronously or
independently by the control room operator. The control room operator may
watch
video of the sockets on the display of the control console 42c to facilitate
engagement
of the sockets with the bolts 91. The arm assemblies may be moved until the
sockets
engage the bolts 91. The wrenches may be operated to tighten the bolts. Torque
and turns may be monitored to control tightening.
[0065]
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.
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[0066] The flanged connection 90u,b may include an upper flange 90u
connected
to the pump section housing 95h, such as by a weld or a threaded connection,
and a
lower flange 90b connected to the pump section housing 95h, such as by a weld
or a
threaded connection. The flanged connection 90u,b,may include an auto
orienting
profile 92 having mating portions formed in each flange 90u,b. The upper
flange 90u
may have passages formed therethrough for receiving one or more threaded
fasteners, such as the bolts 91. The passage may receive a shaft of each bolt
91 and
a head of the bolt may engage an upper surface of the flange 90u when the
shaft is
inserted through the passage. A lower end of the section housing 95h may serve
as
a trap for the bolts 91, thereby preventing escape of the bolts 91 during
insertion of
the section housing into the PCA 240. To trap the bolts 91, the bolts may be
disposed in the passages before the upper flange 90u is connected to the
section
housing 135h. The lower flange 90b may have threaded sockets 93 for receiving
threaded shafts of respective bolts 91, thereby forming the flanged connection
90u,b.
The passages and sockets 93 may be equally spaced around the respective
flanges
90u,b at a predetermined increment, such as ninety degrees for four, sixty
degrees for
six, or forty-five degrees for eight.
[0067] The flanged connection 90u,b may further include a temporary
connection
for each flange 90u,b, such as shearable fasteners 94. One of the shearable
fasteners 94 may torsionally connect the upper shaft coupling 93 of the first
pump
section 95 to the lower flange 90b and another one of the shearable fasteners
94 may
torsionally connect the upper shaft coupling 93 of the second pump section 95
to the
upper flange 90u. The shaft couplings 93 may be temporarily fastened in mating
positions such that when the auto-orienting profile aligns the flanges 90u,b,
the shaft
couplings 93 may also be aligned. The shearable fasteners 94 may fracture in
response to operation of the motor 70 once the ESP 60 has landed in the dock
15.
[0068] To prepare for insertion, the ESP 60 may be assembled into two or
more
deployment sections, such as four. The first deployment section may include
the
motor 70 and the lander 65. The second deployment section may include the
shaft
seal 75. The third deployment section may include the inlet 80 and the first
pump
section 85. The fourth deployment section may include the second pump section
95
and the packoff 99. A length of each deployment section (plus running tool 59)
may
be less than or equal to a length of the tool housing 205h. The arrangement
and
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number of deployment sections may vary based on parameters of the ESP 60, such
as number of stages and components.
[0069] 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).
[0070] The crane may suspend the lubricator 200 while the wireline winch
47 is
operated to lower the first deployment section until the lander 65 and a lower
portion
of the motor 70 are accessible. The motor 70 may then be serviced, such as by
adding motor oil thereto. The lubricator 200 may be lowered onto the PCA 240
using
the crane. The lubricator tee 215 may then be fastened to the upper clamp
241u,
such as by a flanged connection. The seal head 210 may be operated to engage
the
wireline 50. The master 31 and swab 33 valves may then be opened.
[0071] The first deployment section may be lowered into the PCA 240 using
the
wireline 50 until the motor groove 62 is aligned with the upper clamp 241u.
The upper
clamp 241u may then be operated to engage the motor 70, thereby supporting the
first deployment section. The annular BOP 265 may then be operated to engage
the
packing with an outer surface of the motor 70. Since a bottom of the motor 70
may
be sealed, the first deployment section may plug a bore of the PCA 240,
thereby
sealing an upper portion of the PCA from wellbore pressure. The lubricator
connection to the PCA 240 may be disassembled. The upper clamp 241u may also
secure the first deployment section from being ejected from the PCA 240 due to
wellbore pressure. The running tool 59 may be operated to release the first
deployment section using the wireline 50. The lubricator 200 and running tool
59 may
then be removed. The second deployment section may be inserted into the tool
housing 205 and connected to the running tool 59. The lubricator 200 and
second
deployment section may be hoisted over the PCA 240 using the wireline 50
and/or the
crane.
[0072] The crane may suspend the lubricator 200 while the wireline winch 47
is
operated to lower the second deployment section until the lower flange 61 of
the shaft
seal 75 seats on the upper flange 61 of the motor 70. During lowering, the
flanges 61
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may be manually aligned and the upper motor shaft coupling 63 may be manually
aligned and engaged with the lower seal shaft coupling 63. The flanged
connection
61 may be assembled. The lubricator 200 may be lowered onto the PCA 240 using
the crane 90. The lubricator tee 215 may again be fastened to the PCA 240. The
seal head 210 may again be operated to engage the wireline 50. The annular BOP
265 may be disengaged from the motor 70. The upper clamp 241u may be operated
to release the motor 70. The first and second deployment sections may be
lowered
into the PCA 240 until the shaft seal groove 62 is aligned with the upper
clamp 241u.
The upper clamp 241u may then be operated to engage the shaft seal 75, thereby
supporting the first and second deployment sections. The annular BOP 265 may
then
be operated to engage an outer surface of the shaft seal 75.
[0073] The lubricator connection to the PCA 240 may be disassembled. The
running tool 59 may be operated to release the second deployment section using
the
wireline 50. The lubricator 200 and running tool 59 may then be removed. The
third
deployment section may be inserted into the tool housing 205 and connected to
the
running tool 59. The lubricator 200 and third deployment section may be
hoisted over
the PCA 240 using the wireline 80 and/or the crane. The crane may suspend the
lubricator 200 while the wireline winch 47 is operated to lower the third
deployment
section until the lower first pump section flange 61 seats on the upper shaft
seal
flange 61. During lowering, the flanges 61 may be manually aligned and the
upper
seal shaft coupling 63 may be manually aligned and engaged with the lower pump
section shaft coupling 63. The flanged connection 101 may be assembled. The
lubricator 200 may be lowered onto the PCA 240 using the crane 90. The
lubricator
tee 215 may again be fastened to the PCA 240. The seal head 210 may again be
operated to engage the wireline 50. The annular BOP 265 may be disengaged from
the shaft seal 75. The upper clamp 241u may be operated to release the shaft
seal
75. The first, second, and third deployment sections may be lowered into the
PCA
240 until the first pump section groove 62 is aligned with the lower clamp
241b. The
lower clamp 241b may then be operated to engage the first pump section 85,
thereby
supporting the deployment sections.
[0074] Since the third and fourth deployment sections may have open
through-
bores, the open deployment sections may not be used as plugs and the isolation
valve 262 may be used to close the upper portion of the PCA. The running tool
59
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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.
[0075] The lubricator 200 may be lowered onto the PCA 240 using the
crane. The
lubricator tee 215 may again be fastened to the PCA 240. The seal head 210 may
again be operated to engage the wireline 50. The isolation valve 262 may be
opened.
Visibility fluid may be injected into the PCA 240. The running tool 59 and
fourth
deployment section may be lowered into the PCA 240 until the upper first pump
section flange 90u is proximate to the lower second pump section flange 90b.
The
fourth deployment section may be slowly lowered to engage the parts of the
auto-
orienting profile 92 for aligning the flanges 90u,b. Once the auto-orienting
profile 92
has mated, the driver arm assemblies 53 may be operated to engage the bolts
91.
[0076] Each driver motor may be operated to rotate the bolts 91 into
respective
sockets 93. Torque and turns may be monitored by the control room operator
and/or
the PLC 42p to ensure proper assembly. The arm assemblies 53 may be disengaged
from the upper flange 130u. Once the flanged connection 9Oub, has been fully
assembled, the lower clamp 241b may be operated to disengage the first pump
section housing 95h. The cable injector 100 may then be connected to a top of
the
lubricator 200 and closed/assembled around the wireline 50. The cable injector
100
may then be operated to lower the assembled ESP 60 into the wellbore 5w.
[0077] Alternatively, the tool housing 205 may have a length corresponding
to a
length of the ESP 60, thereby obviating the need for the PCA 240.
[0078] Figure 6A illustrates a power cable deployed ESP 360 for use with
a
modified LARS. The modified LARS may be similar to the LARS 1 except that the
LARS truck components may be mounted on a skid frame and the power converter
45 may output a medium voltage DC power signal to the wireline for driving the
ESP
360. The medium voltage power signal may be greater than or equal to one
kilovolt,
such as three to ten kilovolts. The LARS PLC 42p may further include a data
modem
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and a multiplexer for modulating and multiplexing a data signal to/from the
downhole
controller with the DC power signal.
[0079] The ESP 360 may include the electric motor 70, a power conversion
module (PCM) 361, the seal section 75, the inlet 80, the pump 85, a lander
363, an
outlet 364, and a cablehead 365. Additionally, the pump 85 may be a first pump
section and the ESP 360 may further include the second pump section (see pump
section 95). Housings of each of the ESP components may be longitudinally and
torsionally connected, such as by flanged or threaded connections. The
cablehead
365 may include a cable fastener (not shown), such as slips or a clamp for
longitudinally connecting the ESP 360 to the wireline 50.
[0080] The wireline 50 may be longitudinally coupled to the cablehead
365 by a
shearable connection (not shown). The wireline 50 may be sufficiently strong
so that
a margin exists between the deployment weight and the strength thereof. The
cablehead 365 may further include a fishneck so that if the ESP 360 become
trapped
in the wellbore 5w, such as by buildup of sand, the wireline 50 may be freed
from rest
of the components by operating the shearable connection and a fishing tool
(not
shown), may be deployed to retrieve the ESP 360.
[0081] The cablehead 365 may also include leads extending therethrough.
The
leads may provide electrical communication between the conductors of the
wireline
50 and the PCM 361. The PCM 361 may include a power supply, a motor controller
(not shown), a modem (not shown), and multiplexer (not shown). The motor
controller may be similar to the motor controller of the control unit 39. The
power
supply may include one or more DC/DC converters, each converter including an
inverter, a transformer, and a rectifier for converting the DC power signal
into an AC
power signal and reducing the voltage from medium to low. Each converter may
be a
single phase active bridge circuit as discussed and illustrated in PCT
Publication WO
2008/148613, which is herein incorporated by reference in its entirety. The
power
supply may include multiple DC/DC converters in series to gradually reduce the
DC
voltage from medium to low. For the SRM and BLDC motors, the low voltage DC
signal may then be supplied to the motor controller. For the induction motor,
the
power supply may further include a three-phase inverter for receiving the low
voltage
DC power signal from the DC/DC converters and outputting a three phase low
voltage
AC power signal to the motor controller.
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[0082] The PCM modem and multiplexer may demultiplex a data signal from
the
DC power signal, demodulate the signal, and transmit the data signal to the
motor
controller. The motor controller may be in data communication with one or more
sensors (not shown) distributed throughout the ESP 360. A pressure and
temperature (PT) sensor may be in fluid communication with the reservoir fluid
7
entering the inlet 80. A gas to oil ratio (GOR) sensor may also be in fluid
communication with the reservoir fluid 7 entering the inlet 80. A second PT
sensor
may be in fluid communication with the reservoir fluid 35 discharged from the
outlet
364. A temperature sensor (or PT sensor) may be in fluid communication with
the
lubricant to ensure that the motor 70 and PCM 361 are being sufficiently
cooled.
Multiple temperature sensors may also be included in the PCM 361 for
monitoring
and recording temperatures of the various electronic components. A voltage
meter
and current (VAMP) sensor may be in electrical communication with the wireline
50 to
monitor power loss therefrom. A second VAMP sensor may be in electrical
communication with the power supply output to monitor performance of the power
supply. Further, one or more vibration sensors may monitor operation of the
motor
70, the pump 85, and/or the seal section 75. A flow meter may be in fluid
communication with the outlet 364 for monitoring a flow rate of the pump 85.
Utilizing
data from the sensors, the motor controller may monitor for adverse
conditions, such
as pump-off, gas lock, or abnormal power performance and take remedial action
before damage to the pump 85 and/or motor 70 occurs.
[0083] In anticipation of depletion, the production tubing string 310p
may have a
landing nipple 315 installed at a lower end thereof. The landing nipple 315
may have
a seal bore, a torsional coupling, such as an auto-orienting castellation, and
a stop
shoulder. The lander 363 may have a tubing seal, a torsional coupling, such as
an
auto-orienting castellation, and a stop shoulder. Engagement of the lander 363
with
the landing nipple 315 may engage the tubing seal with the seal bore, align
the
castellations, and engage the stop shoulders, thereby longitudinally
supporting the
ESP 360 from the production tubing string 310p and torsionally connecting the
ESP to
the production tubing string, and isolating the inlet 64i from the outlet 640.
[0084] Alternatively, the ESP 360 may include an isolation device having
an
anchor and a packer instead of the lander 363.
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[0085] Figure 6B illustrates insertion of the ESP 360 into the wellbore
5w using the
cable injector 100, according to another embodiment of the present disclosure.
Figure 60 illustrates operation of the power cable deployed ESP 360. Referring
specifically to Figure 6B, the tree valves 31, 33 may be opened. The ESP 360,
running tool 59 and seal head 210 may be assembled, the seal head 210 may be
connected to the tree 30, and the ESP and running tool may be lowered and
suspended in the tree 30, wellhead 10h, and/or upper portion of the wellbore
5w by
the winch 47. The cable injector 100 may then be connected to a top of the
seal head
210 and closed/assembled around the wireline 50. The cable injector 100 may
then
be operated to lower the ESP 360 into the wellbore 5w using the wireline 50
until the
motor 70 is adjacent to the SSV 3.
[0086] Referring specifically to Figure 60, the seal head 210 may then
be operated
to engage the wireline 50 and the SSV 3 opened. The cable injector 100 may
then
continue to lower the ESP 360 to the deployment depth. Once the lander 363 has
engaged the landing nipple 315, the cable injector 100 may be disassembled and
disconnected from the seal head 210. The ESP 360 may then be operated to pump
production fluid 7 from the wellbore 5w.
[0087] Alternatively, the seal head may be operated to engage the
wireline before
lowering the ESP 360 into the wellbore. Alternatively, the rest of the
lubricator 200
may be used to assemble, insert, and/or deploy the ESP 360, as discussed above
for
the ESP 60.
[0088] Figures 7A-7D illustrate insertion of the power cable deployed
ESP 360 into
the wellbore 5w using the cable injector 100, according to another embodiment
of the
present disclosure. Figure 7E illustrates operation of the power cable
deployed ESP
360. Referring specifically to Figure 7A, the tree valves 31, 33 may be
opened. The
ESP 360, running tool 59 and one 225u of the stuffing boxes 225u,b may be
assembled, the stuffing box 225u may be connected to the tree 30, and the ESP
and
running tool may be suspended in the tree 30 and/or upper portion of the
wellbore 5w
by the winch 47. The cable injector 100 may then be connected to a top of the
stuffing box 225u and closed/assembled around the wireline 50. The cable
injector
100 may then be operated to lower the ESP 360 into the wellbore 5w using the
wireline 50 until the motor 70 is adjacent to the SSV 3 and/or the deployment
depth.
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[0089] Referring specifically to Figure 7B, the winch 47 may then be
locked to
suspend the ESP 360. The cable injector 100 may be disassembled and
disconnected from the seal head 210. A mold 301 may be assembled around the
wireline 50 and connected to a top of the stuffing box 225u. A more detailed
discussion regarding use of the mold 301 may be found in U.S. Pat. App. No.
13/447,001 (Atty. Dock. No. ZEIT/0006U5), which is herein incorporated by
reference
in its entirety.
[0090] The mold 301 may be delivered to the wellsite by a service truck
(not
shown). The service truck may include a reaction injector and a crane or
platform to
lift the mold to a top of the stuffing box. The reaction injector may include
a pair of
supply tanks each having a liquid reactive component (aka resin and hardener)
stored
therein. The supply tanks or the components may or may not be heated. The
service
truck may further include a pair of feed pumps, each having an inlet connected
to a
respective supply tank. An outlet of each supply pump may be connected to a
mix
head and an outlet of the mix head may connect to the mold 301. The service
truck
may further include an HPU for powering the supply pumps. The service truck
may
further include a controller for proportioning the feed pumps. The feed pumps
may be
operated to simultaneously supply the liquid reactive components to the mix
head.
The mix head may impinge the liquid components to begin polymerization of the
sealant mixture 345. The sealant mixture 345 may continue from the mix head
into
the mold 301.
[0091] The mold 301 may include a split housing 305 and upper and lower
seals
(not shown). The housing 305 may include a pair of mating semi-tubular
segments
305a,b. Each housing segment 305a,b may have radial couplings, such as flanges
308, formed therealong and half of a longitudinal coupling (not shown), such
as a
flange, formed at one or both longitudinal ends thereof. The radial flanges
308 of
each housing segment 305a,b may be connected to the mating radial flanges by
fasteners 307, such as bolts and nuts. A gasket 309 may be disposed in a
groove
formed in one of the housing segments for sealing the radial connection. Each
seal
may include a pair of mating semi-annular segments.
[0092] 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
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wall of one of the segments 305a,b and in fluid communication with the annulus
312.
An inner diameter of the mold seals may be slightly less than an outer
diameter of the
wireline 50 so that the mold seals engage an outer surface of the wireline the
mold
301 is assembled.
[0093] Referring specifically to Figure 70, the sealant 345 may be a
polymer, such
as an elastomer or thermoplastic elastomer. Once the mold 301 has been
assembled
around the wireline 50, the mix head may be lifted to the mold 301 by the
service
truck crane or the service truck platform may lift the reaction injector to
the mold 301.
The mix head may be connected to the sprue 306. The supply pumps may then be
operated to pump the liquid reactants to the mix head. The sealant mixture 345
may
continue from the mix head into the mold 301. Air displaced by the sealant
mixture
345 may vent from the mold via leakage through and along the armor 57i,o. The
sealant mixture 345 may flow around and along the annulus 312 until the
sealant
mixture 345 encounters the seals. Pressure in the mold 301 may increase and
the
sealant mixture 345 may be forced into the armor 57i,o. Sealant penetration
into the
wireline 50 may be stopped by the outer jacket 56. Pumping of the sealant
mixture
345 may continue until the mold 301 is filled. The mold 301 may be heated by
exothermic polymerization of the mixture 345. A melting temperature of the
mold
seals, gasket 309, and outer jacket 56 may be suitable to withstand the
exothermic
reaction.
[0094] Referring specifically to Figure 7D, once the sealant 345 has
cured and
cooled to at least a point sufficient to maintain structural integrity, the
mix head may
be disconnected from the mold 301 and the mold 301 may be disconnected from
the
stuffing box 225u. The fasteners 307 may then be removed. The service truck
may
further include a hydraulic spreader. The spreader may be connected to the
mold
301 and operated to separate the mold. The service truck may stow the mold 301
and mix head and leave the wellsite. A length of the sealed portion 350 may
correspond to a length of a seal of the stuffing box 225u and be substantially
less
than a length of the wireline 50. An outer diameter of the sealed portion 350
may be
slightly greater than an outer diameter of the rest of the wireline 50.
[0095] Referring specifically to Figure 7D, the stuffing box 225u may
then be
operated to engage the wireline 50 and the SSV 3 opened. The winch 47 may then
be unlocked and operated to lower the ESP 360 to deployment depth.
Alternatively,
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the cable injector 100 may be reinstalled around the sealed portion 350 and
operated
to lower the ESP 360 to deployment depth. As the ESP 360 is lowered, the
sealed
portion 350 may be lowered into alignment with the stuffing box seal as the
lander
363 engages with the landing nipple 315. The ESP 360 may then be operated to
pump production fluid 7 from the wellbore 5w.
[0096] 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.
