Note: Descriptions are shown in the official language in which they were submitted.
CA 02820966 2013-07-12
POWER AND CONTROL POD FOR A SUBSEA ARTIFICIAL LIFT SYSTEM
,
BACKGROUND OF THE INVENTION
Field of the Invention
Embodiments of the present invention generally relate to a power and control
pod for subsea artificial lift system.
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. Current intervention methods of
deployment
and retrieval of submersible pumps require well control by injecting heavy
weight (a.k.a.
kill) fluid in the wellbore to neutralize the flowing pressure thus reducing
the chance of
lose of well control.
SUMMARY OF THE INVENTION
Embodiments of the present invention generally relate to a power and control
pod for subsea artificial lift system. In one embodiment, a method of
operating a
downhole tool in a subsea wellbore includes: supplying a direct current (DC)
power
signal from a dry location to a subsea control pod; converting the DC power
signal to an
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alternating current (AC) power signal by the control pod; and supplying the AC
power
,
= signal from the control pod, into the subsea wellbore, and to the down
hole tool.
In another embodiment, a subsea control pod for an artificial lift system
(ALS)
includes: a cablehead for receiving an umbilical; a diplexer for
separating a
composite signal received by the umbilical into a DC power signal and a
command
signal; a power converter, including: a power supply for reducing voltage of
the DC
power signal from medium to low; and a motor controller for receiving an
output signal
of the power supply and supplying a three phase power signal to an electric
submersible pump (ESP); and a subsea interface for connection to a subsea
production
tree.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the manner in which the above recited features of the present
invention
can be understood in detail, a more particular description of the invention,
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 invention and are
therefore not to be
considered limiting of its scope, for the invention may admit to other equally
effective
embodiments.
Figure 1 illustrates a subsea artificial lift system (ALS), according to one
embodiment of the present invention.
Figure 2A illustrates a launch and recovery system (LARS) of the ALS. Figure
2B illustrates a control pod of the ALS.
Figure 3A illustrates a cable deployed electric submersible pump (ESP) of the
ALS. Figures 3B and 3C illustrate an umbilical of the ALS.
Figure 4 illustrates a subsea tree of the ALS.
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Figure 5A illustrates an insert ESP of a subsea ALS, according to another
,
= embodiment of the present invention. Figure 5B illustrates a
power/deployment cable of
the ALS of Figure 1 and/or the ALS of Figure 5A.
Figure 6 illustrates a subsea tree of the alternative ALS.
DETAILED DESCRIPTION
Figure 1 illustrates a subsea artificial lift system (ALS) 1, according to one
embodiment of the present invention. The ALS 1 may include an electric
submersible
pump (ESP) 100, a deployment cable 250, a subsea production (aka Christmas)
tree
50, a subsea control pod 20, an umbilical 200, and a launch and recovery
system
(LARS) 70. A length of the umbilical 200 may include a vertical depth portion
and a
horizontal step-out portion. The umbilical length may be greater than, equal
to, or
substantially greater than five hundred feet, such as one-quarter, one-half,
three-
quarters, one, two, or five miles.
Figure 2A illustrates the LARS 70. The pod 20 may be launched into the sea 2
from a support vessel (not shown) by the LARS 70. Once deployed, the LARS 70
may
be transported and loaded onto a control platform (not shown). The control
platform
may have personnel stationed onboard or be automated. If automated, the
control
platform may be in communication with an onshore command center, such as by a
satellite transceiver (not shown). Alternatively, the LARS 70 may be located
on any
other dry location, such as on a production platform or onshore. The control
pod 20
may be controlled and supplied with power by the LARS 70. The LARS 70 may
include
a control van 72, a generator 73, a skid frame 74, a power converter 75, a
diplexer
(DIX) 76, a winch 77 having the umbilical 200 wrapped therearound, and a boom
78.
The control van 72 may include a control console 72c and a programmable logic
controller (PLC) 72p.
The generator 73 may be diesel-powered and may supply a one or more phase
(three shown) alternating current (AC) power signal to the power converter 75.
The
power converter 75 may include a one or more (three shown) phase transformer
75t for
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, stepping the voltage of the AC power signal supplied by the generator
73 from a low
,
voltage signal to a medium voltage signal. The low voltage signal may be less
than or
equal to one kilovolt (kV) and the medium voltage signal may be greater than
one kV,
such as five to ten kV. The power converter 75 may further include a one or
more
(three shown) phase rectifier 75r for converting the medium voltage AC signal
supplied
by the transformer 75t to a medium voltage direct current (DC) power signal.
The
rectifier 75r may supply the medium voltage DC power signal to the DIX 76 for
transmission to the control pod 20 via the umbilical 200.
Alternatively, the generator 73 may be omitted and the power converter 75 may
receive the power signal from a generator of the platform instead.
Additionally, the
LARS 70 may include a second power converter (not shown) for powering the
control
van 72.
The PLC 72p may receive commands from a control van operator (not shown)
via the control console 72c and include a data modem (not shown) and
multiplexer (not
shown) for modulating and multiplexing the commands into a data signal for
delivery to
the DIX 76 and transmission to the pod 20 via the umbilical 200. The DIX 76
may
combine the DC power signal and the data signal into a composite signal and
transmit
the composite signal to the pod 20 via the umbilical 200. The DIX 76 may be in
electrical communication with the umbilical 200 via an electrical coupling
(not shown),
such as brushes or slip rings, to allow power and data transmission through
the
umbilical while the winch 77 winds and unwinds the umbilical. The control
console 72c
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 PLC 76 may also receive data signals from
the pod
20, demodulate and demultiplex the data signals, and display the data signals
on the
monitor of the console 72c.
The boom 78 may be an A-frame pivoted to the frame 74 and the LARS 70 may
further include a boom hoist (not shown) having a pair of piston and cylinder
assemblies
(PCAs). Each PCA may be pivoted to each beam of the boom and a respective
column
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of the frame. The LARS may further include a hydraulic power unit (HPU) (not
shown).
The HPU 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 PCAs. The hydraulic pump may be driven by
an
electric motor. The winch 77 may include a drum having the umbilical 200
wrapped
therearound and a motor for rotating the drum to wind and unwind the
umbilical. The
winch motor may be electric or hydraulic. A sheave (not shown) may hang from
the
boom 78. The umbilical 200 may extend through the sheave and an end of the
umbilical may be fastened to a cablehead 21 (Figure 2B) of the pod 20. The
frame 74
may have a platform (not shown) for the pod 20. Pivoting of the A-frame boom
relative
to the support vessel by the PCAs may lift the pod 20 from the platform, over
a rail of
the vessel, and to a position over the waterline 2w. The winch 77 may then be
operated
to lower the pod 20 into the sea 2. Recovery of the pod 20 may be performed by
reversing the steps.
Figures 3B and 3C illustrate the umbilical 200. The umbilical 200 may include
an
inner core 205, an inner jacket 210, a shield 215, an outer jacket 230, one or
more
layers 235i,o of armor, and a cover 240. Alternatively, the cover 240 may be
omitted.
The inner core 205 may be the first conductor and made from an electrically
conductive material, such as aluminum, copper, or alloys thereof. The inner
core 205
may be solid or stranded. The inner jacket 210 may electrically isolate the
core 205
from the shield 215 and be made from a dielectric material, such as a polymer
(i.e.,
polyethylene). The shield 215 may serve as the second conductor and be made
from
the electrically conductive material. The shield 215 may be tubular, braided,
or a foil
covered by a braid. The outer jacket 230 may electrically isolate the shield
215 from the
armor 235i,o and be made from a seawater-resistant dielectric material, such
as
polyethylene or polyurethane. The armor may be made from one or more layers
235i,o
of high strength material (i.e., tensile strength greater than or equal to one
hundred, one
fifty, or two hundred kpsi) to support the pod 20 so that the umbilical 200
may be used
to launch and remove the pod 20 into/from the sea. The high strength material
may be
a metal or alloy and corrosion resistant, such as galvanized steel, aluminum,
or a
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polymer, such as a para-aramid fiber. The armor may include two contra-
helically
wound layers 235i,o of wire, fiber, or strip.
Additionally, the umbilical 200 may include a sheath 225 disposed between the
shield 215 and the outer jacket 230. The sheath 225 may be made from
lubricative
material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape
helically
wound around the shield 215. If lead is used for the sheath 225, a layer of
bedding 220
may insulate the shield 215 from the sheath and be made from the dielectric
material.
Additionally, a buffer 245 may be disposed between the armor layers 235i,o.
The buffer
245 may be tape and may be made from the lubricative material. The cover 240
may
be made from an abrasion resistant material, such as a polymer, such as
polyisoprene
or polyethylene.
Figure 2B illustrates the control pod 20. The pod 20 may be connected to the
LARS 70 by the umbilical 200. The pod 20 may include a frame 24, a cablehead
21, a
PLC 22, one or more power converters, such as a motor converter 25 and an
auxiliary
converter 29, a DIX 26, an interface 28, and an HPU 30. The frame 24 may have
a
base, such as a mud mat or piles, for supporting the pod from the seafloor 2f.
The pod
components may each be connected to the frame 24 within the frame for
protection.
Alternatively, the tree 50 may have a receptacle for receiving the control pod
20.
Alternatively, the pod 20 may be installed on the tree 50 or be an integral
part of the tree
and the pod may be deployed with the tree and the umbilical 200 subsequently
connected to the pod.
The motor converter 25 may be configured to suit the particular type of the
ESP
motor 101 (Figure 3A). The ESP motor 101 may be an induction motor, a switched
reluctance motor (SRM) or a permanent magnet motor, such as a brushless DC
motor
(BLDC). 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
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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 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 motor converter 25 may include a power supply 25i,d and a motor controller
25c. The power supply may include one or more DC/DC converters 25d, 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 DC/DC converter 25d may be a single phase active bridge circuit as
discussed
and illustrated in US Pub. Pat. App. 2010/0206554, which is herein
incorporated by
reference in its entirety. The power supply may include multiple DC/DC
converters 25d
(only one shown) connected 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 25c. For the induction motor, the power supply may
further
include a three-phase inverter 25i for receiving the low voltage DC power
signal from
the DC/DC converters 25d and outputting a three phase low voltage AC power
signal to
the motor controller 25c.
For the induction motor, the motor controller 25c may be a switchboard (i.e.,
logic
circuit) for simple control of the motor 101 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 25c may receive the low
voltage DC power signal from the power supply and sequentially switch phases
of the
motor, thereby supplying an output signal to drive the phases of the motor
101. The
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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.
The motor controller 25c may output one or more (three shown) phase power
signals to the interface 28 (i.e., junction plate) connected to the frame 24.
The tree 50
may have a corresponding interface 58 (Figure 4). The interfaces 28, 58 may be
connected by jumpers (aka flying leads). The jumpers may be connected to the
interfaces 28, 58 by a remotely operated vehicle (ROV, not shown) deployed
from the
support vessel. Alternatively, if the tree 50 has a pod receptacle, the
interfaces may be
include respective pins and sockets of a stab connector.
The pod PLC 22 may include a modem and multiplexer for receiving data signals
from the LARS 70 via the DIX 26 and transmitting data signals to the LARS via
the DIX.
The pod PLC 22 may be in data communication with the DIX 26, the HPU 30, the
motor
controller 25c, and the interface 22. The pod PLC 22 may relay commands from
the
LARS 70 to the motor controller 25c regarding operation of the ESP 100. The
pod PLC
22 may also relay feedback from the motor controller 25c to the LARS 70. The
pod
PLC 22 may also control operation of the HPU 30 in response to commands from
the
LARS 70. The pod PLC 22 may monitor operation of the HPU 30 and relay feedback
from the HPU to the LARS 70. The HPU 30 may be similar to the LARS HPU,
discussed above. The HPU 30 may be in hydraulic communication with the
interface
28.
The auxiliary converter 29 may receive the medium voltage DC power signal
from the umbilical 200 an convert the signal to an ultra-low voltage DC power
signal for
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powering the PLC 22 and HPU 30. The auxiliary converter 29 may include one or
more
of the DC/DC converters, discussed above. Alternatively, the auxiliary
converter 29
may connect to an output of the motor converter 25 instead of the DIX 26 or
may be
integrated with the motor converter. Alternatively, the HPU 30 may be AC
powered.
Figure 4 illustrates the subsea production tree 50. The tree 50 may be
connected to the wellhead 10h, such as by a collet, mandrel, or clamp tree
connector.
The tree 50 may be vertical (not shown) or horizontal (shown). If the tree 50
is vertical,
it may be installed after production tubing 10p is hung from the wellhead 10h.
If the tree
50 is horizontal, the tree may be installed and then the production tubing 10p
may be
hung from the tree 50. The tree 50 may include fittings and valves to control
production
7 from the wellbore 5 into a pipeline (not shown) which may lead to a
production facility
(not shown), such as a production vessel or platform.
The tree 50 may include a head 51, a wellhead connector 52, a tubing hanger
53, an internal cap 54, an external cap 55, an upper crown plug 56u, a lower
crown plug
56b, a production valve 57p, one or more annulus valves (not shown), and a
deployment cable hanger 60. Each of the components 51-54 may have a
longitudinal
bores extending therethrough. The tubing hanger 53 and head 51 may each have a
lateral production passage formed through walls thereof for the flow of
production fluid
7. The tubing hanger 53 may be disposed in the head bore. The tubing hanger 53
may
support the production tubing 10p. The tubing hanger 53 may be fastened to the
head
by a latch 53b. The latch 53b may include one or more fasteners, such as dogs,
an
actuator, such as a cam sleeve. The cam sleeve may be operable to push the
dogs
outward into a profile formed in an inner surface of the tree head 51. The
latch 53b may
further include a collar for engagement with a running tool (not shown) for
installing and
removing the tubing hanger 53.
The tubing hanger 53 may be rotationally oriented and longitudinally aligned
with
the tree head 51. The tubing hanger 53 may further include seals 53s disposed
above
and below the production passage and engaging the tree head inner surface. The
tubing hanger 53 may also have a number of auxiliary ports/conduits spaced
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circumferentially there-around. Each port/conduit may align with a
corresponding
' port/conduit in the tree head 51 for hydraulic or electrical
communication with the tubing
hanger 53. The tubing hanger 53 may have an annular, partially spherical
exterior
portion that lands within a partially spherical surface formed in tree head
51.
The annulus 10a may communicate with an annulus passage (not shown)
formed through and along the head 51 for and bypassing the seals 53s. The
annulus
passage may be accessed by removing internal tree cap 54. The tree cap 54 may
be
disposed in head bore above tubing hanger 53. The tree cap 54 may have a
downward
depending isolation sleeve received by an upper end of tubing hanger 53.
Similar to the
tubing hanger 53, the tree cap 54 may include a latch 54b fastening the tree
cap to the
head 51. The tree cap 54 may further include a seal 54s engaging the head
inner
surface. The production valve 57p may be disposed in the production passage
and the
annulus valves may be disposed in the annulus passage. Ports/conduits (not
shown)
may extend through the tree head 51 to the interface 58 for electrical or
hydraulic
operation of the valves 57p.
The upper crown plug 56u may be disposed in tree cap bore and the lower crown
plug 56b may be disposed in the tubing hanger bore. Each crown plug 56u,b may
have
a body with a metal seal on its lower end. The metal seal may be a depending
lip that
engages a tapered inner surface of the respective cap and hanger. The body may
have
a plurality of windows which allow fasteners, such as dogs, to extend and
retract. The
dogs may be pushed outward by an actuator, such as a central cam. The cam may
have a profile on its upper end for engagement by a running tool (not shown).
The cam
may move between a lower locked position and an upper position freeing dogs to
retract. A retainer may secure to the upper end of body to retain the cam.
The cable hanger 60 may include a tubular body 61 having a bore therethrough,
one or more leads 60b, a part of one or more (three shown) electrical
couplings 60c,
one or more seals 60s, and a cablehead 67. The cable head 67 may be connected
to
the cable hanger 60, such as by fastening (i.e., threaded or flanged
connection). The
cable hanger 60 may be connected to the tubing hanger 53 by resting on a
shoulder
= CA 02820966 2013-07-12
formed in an inner surface of the tubing hanger. Alternatively or
additionally, the cable
' hanger 60 may be fastened to the tubing hanger 53 by a latch (not shown).
Each lead 60b may be electrically connected to a respective conductor of the
cable 250. Each lead 60b may extend from the cable head 67 to a respective
coupling
part 60c and be electrically connected to the cable conductor and the coupling
part.
Each coupling part 60c may include a contact, such as a ring, encased in
insulation.
The ring may be made from an electrically conductive material, such as
aluminum,
copper, aluminum alloy, copper alloy, or steel. The ring may also be split and
biased
outwardly. The insulation may be made from a dielectric material, such as a
polymer
(i.e., an elastomer or thermoplastic).
The tubing hanger 53 may include the other coupling parts 53c for receiving
the
respective cable hanger coupling parts 60c, thereby electrically connecting
the cable
hanger 60 and the tubing hanger 53. A lead 53b may be electrically connected
to each
tubing hanger coupling part 53c and extend through the tubing hanger 53 to a
part of an
electrical coupling electrically connecting the tubing hanger lead 53b with a
tree head
lead 51b. The tree head leads 51b may extend to the interface 58, thereby
providing
electrical communication between the pump controller 25c and the cable 250.
The cable
250 may extend from the cable head 67 through the wellhead 10h and to a cable
head
107 (Figure 3A) of the ESP 100. Each of the cable heads 67, 107 may include a
cable
fastener (not shown), such as slips or a clamp for longitudinally connecting
the cable
250.
Additionally, functions of the tree 50, such as operation of the production
valve
57p and the annulus valves, may also be controlled by the pod 20. One or more
additional jumpers may extend to the pod 20 and provide communication between
the
tree valves 57p and the HPU 30 (if the valve actuators are hydraulic) or the
pod PLC 22
(if the valve actuators are electric). Alternatively, the tree 50 may have a
separate
controller and the pod 20 may interface with the tree controller.
Additionally, the pod 20
may be a manifold serving a plurality of trees 50 and ESPs 100.
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Figures 5B illustrates the deployment cable 250. The cable 250 may include a
core 257 having one or more (three shown) wires 255 and a jacket 256, and one
or
more layers 260i,o of armor. Each wire 255 may include a conductor 251, a
jacket 252,
a sheath 253, and bedding 254. The conductors 251 may each be made from an
electrically conductive material, such as aluminum, copper, or alloys thereof.
The
conductors 251 may each be solid or stranded. Each jacket 252 may electrically
isolate
a respective conductor 251 and be made from a dielectric material, such as a
polymer
(i.e., ethylene propylene diene monomer (EPDM)). Each sheath 253 may be made
from lubricative material, such as polytetrafiuoroethylene (PTFE) or lead, and
may be
tape helically wound around a respective wire jacket 252. Each bedding 254 may
serve
to protect and retain the respective sheath 253 during manufacture and may be
made
from a polymer, such as nylon. The core jacket 256 may protect and bind the
wires 255
and be made from a polymer, such as EPDM or nitrile rubber.
The armor may be made from one or more layers 260i,o of high strength material
(i.e., tensile strength greater than or equal to one hundred, one fifty, or
two hundred
kpsi) to support the ESP 100 so that the umbilical cable 250 may be used to
deploy and
remove the ESP into/from the wellbore 5. 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 may include two contra-helically wound layers
260i,o of
wire, fiber, or strip. Additionally, a buffer (not shown) may be disposed
between the
armor layers 260i,o. The buffer may be tape and may be made from the
lubricative
material. Additionally, the cable 250 may further include a pressure
containment layer
258 made from a material having sufficient strength to contain radial thermal
expansion
of the core 257 and wound to allow longitudinal expansion thereof.
Figure 3A illustrates the ESP 100. The wellbore 5 has been drilled from the
seafloor 2f into a hydrocarbon-bearing (i.e., crude oil and/or natural gas)
reservoir 6. A
string of casing 10c has been run into the wellbore 5 and set therein with
cement (not
shown). The casing 10c has been perforated 9 to provide to provide fluid
communication between the reservoir 6 and a bore of the casing 10c. The casing
10c
extends into the wellbore 5 from the wellhead 10h. A string of production
tubing 10p
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extends from the tree 50 to the reservoir 6 to transport production fluid 7
from the
reservoir 6 to the tree 50. A packer 8 has been set between the production
tubing 10p
and the casing 10c to isolate an annulus 10a formed between the production
tubing and
the casing from production fluid 7.
A subsurface safety valve (SSV) 3 may be assembled as part of the production
tubing string 10p. 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 290 extending along
an outer
surface of the production tubing 10p to the wellhead 10h. Injection of
hydraulic fluid into
the 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.
The production tubing 10p may further include one or more sensors 4u,b. 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 106o of the ESP 100 and a lower sensor 4b
is in fluid
communication with an inlet 104i of the ESP 100. The sensors 4u,b may be in
data
communication with the pod PLC 22 via a data conduit of the control line 290,
such as
an electrical or optical cable. The data conduit may also provide power for
the sensors.
The control line 290 may also be connected to the tubing hanger 53 and the
tubing
hanger and tree head 51 may each include parts of respective data and
hydraulic
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cables to provide communication with the tree interface 58. Jumpers may
provide
,
respective hydraulic and data communication with the pod 20.
The pod PLC 22 may receive measurements from the sensors 4u,b and relay the
measurements to the LARS van 72 for monitoring operation of the ESP 100 by the
van
operator. The pod PLC 22 may also relay the measurements to the pump
controller
25c. The pod HPU 30 may be in hydraulic communication with the SSV 3 for
operation
thereof. The van operator may adjust operation of the ESP 100 in response to
monitoring the pressure sensors, such as adjusting a speed of the motor 101.
Alternatively, any of the PLCs 22, 72p or motor controller 25c may adjust
operation of
the ESP autonomously. Additionally, the van operator or controllers 22, 72p
may
monitor the ESP 100 for adverse conditions, such as pump-off, gas lock, or
abnormal
power performance and take remedial action before damage to the pump 104
and/or
motor 101 occurs.
=
The ESP 100 may include the electric motor 101, a seal section 103, a pump
104, an isolation device 106, a cablehead 107, and a flat cable 108. Housings
of each
of the ESP components may be longitudinally and torsionally connected, such as
by
flanged or threaded connections.
The cable 250 may be longitudinally coupled to the cablehead 107 by a
shearable connection (not shown). The cable 250 may be sufficiently strong so
that a
margin exists between the ESP deployment weight and the strength of the cable.
For
example, if the deployment weight is ten thousand pounds, the shearable
connection
may be set to fail at fifteen thousand pounds and the cable may be rated to
twenty
thousand pounds. The cablehead 107 may further include a fishneck so that if
the ESP
100 become trapped in the wellbore 5, such as by jamming of the isolation
device 106
or buildup of sand, the cable 250 may be freed from rest of the components by
operating the shearable connection and a fishing tool (not shown), such as an
overshot,
may be deployed to retrieve the ESP 100.
The cablehead 107 may also include leads (not shown) extending therethrough
and through the isolation device 106. The leads may provide electrical
communication
14
. = CA 02820966 2013-07-12
between the conductors 251 of the cable 250 and conductors of the flat cable
108. The
' flat cable 108 may extend along the pump 104 and the seal section 103 to
the motor
101. The flat cable 108 may have a low profile to account for limited annular
clearance
between the components 103, 104 and the production tubing 10p. The flat cable
108
may only need to support its own weight. The flat cable 108 may be armored by
a
metal or alloy. Alternatively, two or more, such as three, flat leads may be
spaced
around the pump 104 and the seal section 103 and connect the cable conductors
251 to
the motor 101 instead of the flat cable 108. Alternatively, the motor 101 may
be located
above the seal section 103, the pump 104 and isolation device 106 may be
located
below the seal section, and the flat cable 108 may be omitted.
The motor 101 may be filled with a dielectric, thermally conductive liquid
lubricant, such as motor oil. The motor 101 may be cooled by thermal
communication
with the production fluid 7. The motor 101 may include a thrust bearing (not
shown) for
supporting a drive shaft (not shown). In operation, the motor 101 may rotate
the drive
shaft, thereby driving a pump shaft (not shown) of the pump 104. The drive
shaft may
be directly connected to the pump shaft (no gearbox).
The seal section 103 may isolate the reservoir fluid 7 being pumped through
the
pump 104 from the lubricant in the motor 101 by equalizing the lubricant
pressure with
the pressure of the reservoir fluid 7. The seal section 103 may torsionally
connect the
drive shaft to the pump shaft. The seal section 103 may house a thrust bearing
capable
of supporting thrust load from the pump 104. The seal section 103 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 104i 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 allowing reservoir
fluid 7 to enter
a lower or first stage of the pump 104. The standard inlet may include a
screen to filter
CA 02820966 2013-07-12
. 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 7.
The isolation device 106 may include a packer, an anchor, and an actuator. The
actuator may be operated mechanically by articulation of the cable 250,
electrically by
power from the cable, or hydraulically by discharge pressure from the pump
104. The
packer may be made from a polymer, such as a thermoplastic, elastomer, or
copolymer,
such as rubber, polyurethane, or PTFE. The isolation device 106 may have a
bore
formed therethrough in fluid communication with the pump outlet and have one
or more
discharge ports 1060 formed above the packer for discharging the pressurized
reservoir
fluid 7 into the production tubing 10p. Once the ESP 100 has reached
deployment
depth, the isolation device actuator may be operated, thereby setting the
anchor and
expanding the packer against the production tubing 10p, isolating the pump
inlet 104i
from the pump outlet, and torsionally connecting the ESP 100 to the production
tubing
10p. The anchor may also longitudinally support the ESP 100.
Additionally, the isolation device 106 may include a bypass vent (not shown)
for
releasing gas separated by the pump inlet 104i that may collect below the
isolation
device and preventing gas lock of the pump 104. A pressure relief valve (not
shown)
may be disposed in the bypass vent. Additionally, a downhole tractor (not
shown) may
be integrated into the cable 250 to facilitate the delivery of the ESP 100,
especially for
highly deviated wells, such as those having an inclination of more than forty-
five
degrees or dogleg severity in excess of five degrees per one hundred feet. The
drive
and wheels of the tractor may be collapsed against the cable and deployed when
required by a signal from the surface.
The pump 104 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. The pump 104 may include one or more stages (not
shown).
Each stage of the centrifugal pump may include an impeller and a diffuser. The
impeller
may be torsionally and longitudinally connected to the pump shaft, such as by
a key.
16
, = CA 02820966 2013-07-12
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 104 may
deliver
the pressurized reservoir fluid 7 to the isolation device bore.
Alternatively, the pump 104 may be a high speed compact pump discussed and
illustrated at Figures 1C 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). The compact pump may include one or more stages, such as three.
Each stage may include a housing, a mandrel, and an annular passage formed
between
the housing and the mandrel.
The mandrel may be disposed in the housing. The
mandrel may include a rotor, one or more helicoidal rotor vanes, a diffuser,
and one or
more diffuser vanes. The rotor may include a shaft portion and an impeller
portion. The
rotor may be supported from the diffuser for rotation relative to the diffuser
and the
housing by a hydrodynamic radial bearing formed between an inner surface of
the
diffuser and an outer surface of the shaft portion. The rotor vanes may
interweave to
form a pumping cavity therebetween. A pitch of the pumping cavity may increase
from
an inlet of the stage to an outlet of the stage. The rotor may be
longitudinally and
torsionally connected to the motor drive shaft and be rotated by operation of
the motor.
As the rotor is rotated, the production fluid 7 may be pumped along the cavity
from the
inlet toward the outlet. The annular passage may have a nozzle portion, a
throat
portion, and a diffuser portion from the inlet to the outlet of each stage,
thereby forming
a Venturi.
Additionally, the ESP 100 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 100. The controller may transmit data
from the
sensors to the motor controller via conductors 251 of the cable 250.
Alternatively, the
cable 250 may further include a data conduit, such as data wires or optical
fiber, for
17
CA 02820966 2013-07-12
transmitting the data. A PT sensor may be in fluid communication with the
reservoir
fluid 7 entering the pump inlet 1041. A GOR sensor may also be in fluid
communication
with the reservoir fluid 7 entering the pump inlet 1041. A second PT sensor
may be in
fluid communication with the reservoir fluid 7 discharged from the pump
outlet/ports
1060. A temperature sensor (or PT sensor) may be in fluid communication with
the
lubricant to ensure that the motor 101 is being sufficiently cooled. A voltage
meter and
current (VAMP) sensor may be in electrical communication with the cable 250 to
monitor power loss from the cable. Further, one or more vibration sensors may
monitor
operation of the motor 101, the pump 104, and/or the seal section 103. A flow
meter
may be in fluid communication with the pump outlet for monitoring a flow rate
of the
pump 104. Alternatively, the tree 50 may include a flow meter (not shown) for
measuring a flow rate of the pump 104 and the tree flow meter may be in data
communication with the control pod 20.
The ESP 100 may be retrieved periodically for maintenance or replacement. To
retrieve the ESP 100, a lubricator (not shown, see '547 application), may be
deployed
and landed on to the tree 50 by a support vessel. The lubricator may be used
to
retrieve the ESP 100 to the vessel and redeploy a repaired/replacement ESP
riserlessly
and without killing the reservoir 6. Alternatively, a mobile offshore drilling
unit (MODU)
may be used to retrieve and redeploy a repaired/replacement ESP using a riser
and a
lubricator. For either approach, a running tool may be deployed using wireline
and
connect to a profile formed in an inner surface of the cable hanger 60. The
cable
hanger 60 may then be lifted from the tree 50 and the cable 250 may carry the
ESP 100
along therewith. The repaired/replacement ESP may also be deployed in a
similar
fashion.
Figure 5A illustrates an insert ESP 300 of a subsea ALS, according to another
embodiment of the present invention. The ESP 300 may be similar to the ESP 100
except that instead of being deployed by the cable 250, the cable 250 is
deployed with
the production tubing 10p and the production tubing includes a dock 310 for
receiving a
lander 305 of the ESP 300. The dock 310 may include a penetrator 310p for
receiving
an end of the cable 250. The cable 250 may be fastened along an outer surface
of the
18
CA 02820966 2013-07-12
production tubing 10p at regular intervals, such as by clamps or bands (not
shown).
'
Each of the lander 305 and dock 310 may include part, such as a pin or box,
of a wet
mateable connector 305w, 310w. The wet matable connector 305w, 310w may
include
one or more pairs, such as three, of pins and boxes for each conductor 251 of
the cable
250 and phase of the motor 101. The lander 305 may have a flow passage formed
therethrough for the intake of production fluid 7 and leads providing
electrical
communication between the pins 305w and the motor 101. 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.
Each of the lander 305 and dock 310 may also include part of an auto-orienter
305c, 310f. The auto-orienter may include a cam 305c and one or more followers
310f.
As the ESP 300 is lowered into the dock, the auto-orienter may rotate the ESP
to align
the pins 305w with the respective boxes 310w. Each of the lander 305 and dock
310
may further include one or more parts, such as splines 305s, 310s, of a torque
profile.
Engagement of the splines 305s, 310s may torsionally connect the ESP 300 to
the
production tubing 310. A landing shoulder may be formed at a top of each of
the
splines 305s to longitudinally support the ESP 300 in the production tubing
10p. The
ESP 300 may include the isolation device 306 instead of the isolation device
106. The
isolation device 306 may have one or more fixed seals received by a polished
bore
receptacle 310r of the dock 310, thereby isolating discharge ports (not shown)
of the
isolation device from the pump inlet 104i. The isolation device 306 may
further include
a latch (not shown) operable to engage a latch profile (not shown) of the dock
310,
thereby longitudinally connecting the ESP 300 to the production tubing 10p.
The isolation device 306 may further include a fishing profile, such as a
neck, or
inner profile, for engagement with a running tool (not shown). The running
tool may be
deployed as a bottomhole assembly (BHA) of a wireline or coiled tubing
workstring to
retrieve the ESP 300 for maintenance/replacement and to deploy a
repaired/replacement ESP. The ESP 300 may be initially deployed with the
production
tubing 10p or using the running tool. The running tool may include a latch for
engaging
the fishing neck/inner profile. The fishing neck/inner profile may be operably
coupled to
19
CA 02820966 2013-07-12
the isolation device 306 to release the isolation device latch in response to
articulation
of the workstring. When deploying the ESP 300, the isolation device latch may
set by
articulation of the workstring. The running tool may further include a seal
for engaging
an inner surface of the production tubing so pumping may be used to assist
deployment
of the running tool. A suitable running tool is discussed and illustrated in
U.S. Pat. No.
6,415,869, which is herein incorporated by reference in its entirety.
Additionally, the ESP 300 may further include a sensor sub as discussed above
for the ESP 100. Alternatively, a tubing deployed ESP (not shown) may be used
with
the alternative ALS instead of the insert ESP 300. Alternatively, the cable
deployed
ESP 100 may include the isolation device 306 instead of the isolation device
106.
Figure 6 illustrates a subsea production tree 350 of the alternative ALS.
Instead
of the cable hanger 60, the tubing hanger 353 may include a cablehead 367 for
receiving the cable 250 and providing electrical communication between the
cable
conductors 251 and respective leads 353b.
While the foregoing is directed to embodiments of the present invention, other
and further embodiments of the invention may be devised without departing from
the
basic scope thereof, and the scope thereof is determined by the claims that
follow.
