U.S. patent application number 13/031044 was filed with the patent office on 2012-08-23 for cable deployed downhole tubular cleanout system.
Invention is credited to Matthew Crowley, Lance I. Fielder, Evan Sheline, Bruce H. Storm, JR..
Application Number | 20120211229 13/031044 |
Document ID | / |
Family ID | 46651801 |
Filed Date | 2012-08-23 |
United States Patent
Application |
20120211229 |
Kind Code |
A1 |
Fielder; Lance I. ; et
al. |
August 23, 2012 |
CABLE DEPLOYED DOWNHOLE TUBULAR CLEANOUT SYSTEM
Abstract
Embodiments of the present invention generally relate to cable
deployed downhole tubular clean out system. In one embodiment, a
method of cleaning a tubular string disposed in a wellbore includes
connecting a cable to a BHA. The BHA includes a motor and a
cleaner. The method further includes supplying a power signal to
the BHA through the cable, thereby operating the motor to rotate
the cleaner; deploying the BHA into the tubular string and the
wellbore using the cable; and cleaning a deposit from an inner
surface of the tubular string using the rotating cleaner.
Inventors: |
Fielder; Lance I.; (Sugar
Land, TX) ; Sheline; Evan; (Houston, TX) ;
Crowley; Matthew; (Houston, TX) ; Storm, JR.; Bruce
H.; (Houston, TX) |
Family ID: |
46651801 |
Appl. No.: |
13/031044 |
Filed: |
February 18, 2011 |
Current U.S.
Class: |
166/311 ;
166/170 |
Current CPC
Class: |
E21B 37/00 20130101 |
Class at
Publication: |
166/311 ;
166/170 |
International
Class: |
E21B 37/00 20060101
E21B037/00 |
Claims
1. A method of cleaning a tubular string disposed in a wellbore,
comprising: connecting a cable to a BHA, the BHA comprising a motor
and a cleaner; supplying a power signal to the BHA through the
cable, thereby operating the motor to rotate the cleaner; deploying
the BHA into the tubular string and the wellbore using the cable;
and cleaning a deposit from an inner surface of the tubular string
using the rotating cleaner.
2. The method of claim 1, wherein: the wellbore is live, tubular
string is a production string, and the BHA is deployed also using a
lubricator.
3. The method of claim 1, wherein: the BHA further comprises an
anti-rotation guide and a tractor, and the motor also operates the
tractor to propel the BHA along the tubular string.
4. The method of claim 1, wherein the cleaner comprises a first set
of brushes disposed therearound and a first set of scrapers
disposed therearound.
5. The method of claim 4, wherein: the cleaner further comprises a
second set of brushes and a second set of scrapers, the BHA further
comprises: a first speed reducer operable to rotate the first sets
at a first speed substantially less than a rotational speed of the
drive shaft; and a second speed reducer operable to counter-rotate
the second sets relative to the drive shaft and the first sets at
the first speed.
6. The method of claim 1, wherein: the power signal is DC, and the
BHA further comprises a power conversion module operable to receive
the power signal and supply a second power signal to the motor.
7. The method of claim 1, further comprising swabbing the tubular
string using the BHA after cleaning.
8. The method of claim 7, wherein: a first length of the tubular
string is cleaned, and the method further comprises: swabbing the
first length of the production tubing after cleaning the first
length; and cleaning a second length of the production tubing after
swabbing the first length.
9. The method of claim 1, further comprising spraying the cleaner
with a fluid.
10. The method of claim 9, wherein the fluid is injected through
the cable to the BHA.
11. The method of claim 9, wherein: the BHA is connected to a
coiled tubing string, and the fluid is injected through an annulus
formed between the cable and the coiled tubing to the BHA.
12. A bottom hole assembly (BHA) for cleaning a tubular string
disposed in a wellbore, comprising: a cablehead; a drive shaft; a
submersible electric motor operable to rotate the drive shaft; a
cleaner rotationally connected to the drive shaft; an anti-rotation
guide operable to engage the tubular string and connected to a
housing of the motor; a tractor rotationally connected to the drive
shaft and operable to propel the BHA along the tubular string; and
a power conversion module operable to receive a DC power signal
from the cablehead and supply a second power signal to the
motor.
13. The BHA of claim 12, wherein the tractor comprises a polymer
screw operable to engage an inner surface of the tubular
string.
14. The BHA of claim 12, wherein the cleaner comprises a first set
of brushes disposed therearound and a first set of scrapers
disposed therearound
15. The BHA of claim 14, wherein: the cleaner further comprises a
second set of brushes and a second set of scrapers, the BHA further
comprises: a first speed reducer operable to rotate the first sets
at a first speed substantially less than a rotational speed of the
drive shaft; and a second speed reducer operable to counter-rotate
the second sets relative to the drive shaft and the first sets at
the first speed.
16. The BHA of claim 15, further comprising a third speed reducer
operable to rotate the tractor at a second speed substantially less
than the first speed.
17. The BHA of claim 12, wherein: the drive shaft has a bore, and
the BHA further comprises: a hydraulic swivel in fluid
communication with the bore, and an injector in fluid communication
with the bore and operable to spray the cleaner with a fluid.
18. The BHA of claim 17, further comprising: a coiled tubing head;
and a fluid conduit in communication with the coiled tubing head
and the hydraulic swivel.
19. A downhole assembly, comprising: the BHA of 12; and a cable
having two or less conductors and a strength sufficient to support
the BHA.
20. The downhole assembly of claim 19, wherein the cable has a
fluid conduit.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] Embodiments of the present invention generally relate to a
cable deployed downhole tubular clean out system.
[0003] 2. Description of the Related Art
[0004] FIG. 1A illustrates a prior art producing wellbore 5. The
wellbore 5 has been drilled from a surface 1s of the earth into a
hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir
25. 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
30 to provide to provide fluid communication between the reservoir
25 and a bore of the casing 10c. A wellhead 15 has been mounted on
an end of the casing string 10c. A string of production tubing 10p
extends from the wellhead 15 to the formation 25 to transport
production fluid 35 from the formation to the surface 1s. A packer
12 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 35.
[0005] A production (aka Christmas) tree 50 may be installed on the
wellhead 15. The production tree 50 may include a master valve 51,
tee 52, a swab valve 53, a cap 54, and a production choke 55.
Production fluid 35 from the reservoir 25 may enter a bore of the
production tubing 10p, travel through the tubing bore to the
surface 1s. The production fluid may continue through the master
valve 51, the tee 52, and through the choke 55 to a flow line (not
shown). The production fluid 35 may continue through the flowline
to surface separation, treatment, and storage equipment (not
shown).
[0006] Over time, solids may precipitate from the production fluid
35 and form a deposit 40 on the production tubing 10p. The deposit
40 may include scale precipitating from brine in the production
fluid 35 and/or paraffin precipitating from crude oil in the
production fluid. The deposit may 40 build until flow through the
production tubing 10p is obstructed requiring cleanout by an
intervention operation. Alternatively, the production tubing 10p
may be cleaned out before installation of an artificial lift system
or reinstallation of the artificial system after intervention to
repair the artificial lift system. The intervention operation is
conducted by fixing a cleaning tool to an end of a drill pipe
string, running the cleaning tool into the wellbore 5, and rotating
and moving the cleaning tool along the wellbore 5 using the drill
pipe string. This operation requires deployment of a workover rig
to the well site and use of the workover rig for several days to
assemble the drill pipe string, perform the operation, and
disassemble the drill pipe string.
SUMMARY OF THE INVENTION
[0007] Embodiments of the present invention generally relate to
cable deployed downhole tubular clean out system. In one
embodiment, a method of cleaning a tubular string disposed in a
wellbore includes connecting a cable to a BHA. The BHA includes a
motor and a cleaner. The method further includes supplying a power
signal to the BHA through the cable, thereby operating the motor to
rotate the cleaner; deploying the BHA into the tubular string and
the wellbore using the cable; and cleaning a deposit from an inner
surface of the tubular string using the rotating cleaner.
[0008] In another embodiment, a bottom hole assembly (BHA) for
cleaning a tubular string disposed in a wellbore includes a
cablehead; a drive shaft; a submersible electric motor operable to
rotate the drive shaft; a cleaner rotationally connected to the
drive shaft; an anti-rotation guide operable to engage the tubular
string and connected to a housing of the motor; a tractor
rotationally connected to the drive shaft and operable to propel
the BHA along the tubular string; and a power conversion module
operable to receive a DC power signal from the cablehead and supply
a second power signal to the motor.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] 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.
[0010] FIG. 1 illustrates a prior art producing wellbore obstructed
by deposit buildup in the production tubing.
[0011] FIG. 2 illustrates a cable deployed bottomhole assembly
(BHA) for performing a cleanout operation, according to one
embodiment of the present invention.
[0012] FIG. 2A is a layered view of the cable. FIG. 2B is an end
view of the cable.
[0013] FIGS. 3A-3J illustrate a method of deploying the BHA into a
live wellbore and cleaning the wellbore, according to another
embodiment of the present invention.
[0014] FIG. 4A illustrates a BHA, according to another embodiment
of the present invention. FIG. 4B illustrates a cable for deploying
the BHA.
[0015] FIG. 5 illustrates a BHA, according to another embodiment of
the present invention.
DETAILED DESCRIPTION
[0016] FIG. 2 illustrates a cable deployed bottomhole assembly
(BHA) 100 for performing a cleanout operation, according to one
embodiment of the present invention. The BHA 100 may include a
cablehead 105, an anti-rotation guide 110, a power conversion
module (PCM) 115, a submersible electric motor 120, one or more
speed reducers 125f,r, 135, a cleaner 130, a tractor 140, a mandrel
145, and a drive shaft 150. Housings of the components 110-125, 135
may be tubular and rotationally stationary and longitudinally and
rotationally connected, such as by flanged or threaded connections.
The mandrel 145 may be tubular, rotationally stationary, and extend
through the cleaner 130 to connect housings of the speed reducers
125f,r, 135. The components 130, 140 may be rotated (indirectly) by
the drive shaft 150 and housings thereof may be tubular. The BHA
100 may be deployed with and powered by a cable 160.
[0017] The cablehead 105 may include a cable fastener 105f, such as
slips or a clamp for connecting to the cable 160 and a swivel 105s
allowing relative rotation between the BHA 100 and the cable 160
while longitudinally connecting the BHA and the cable. The
cablehead 105 may also provide electrical communication between the
cable 160 and the PCM 115. The cablehead 105 may further include a
shearable connection (not shown) set to fail at a predetermined
overpull (less than a strength of the cable 160). The cablehead 105
may further include a fishneck so that if the BHA 100 becomes
trapped in the wellbore, the cable 160 may be freed from the BHA
100 by operating the shearable connection and a fishing tool (not
shown), such as an overshot, may be deployed to retrieve the BHA
100.
[0018] The anti-rotation guide 110 may include one or more sets of
rollers 111 for engaging an inner surface of the production tubular
10p. The rollers 111 and guide housing may be sized such that an
overall diameter of the guide (housing+rollers) may correspond to
the drift diameter of the production tubing 10p, such as slightly
greater than the drift diameter to ensure tight engagement. Each
set may include a plurality of rollers 111 oriented to rotationally
connect the housing of the guide to the production tubing 10p while
allowing the guide housing to move longitudinally relative to the
production tubing 10p. The rollers 111 may be may be made from a
slip-resistant material or include a rim and a tire made from the
slip resistant material. The slip resistant material may be a
polymer, such as an elastomer or elastomer copolymer. Reaction
torque from the motor 120 may be transferred to the production
tubing 10p due to the engagement of the rollers 111 with the
production tubing. Alternatively, sprockets, drag blocks, or drag
springs may be used instead of the rollers 111.
[0019] The PCM 115 may include a power supply (not shown), motor
controller (not shown), a modem (not shown), and a demultiplexer
(not shown). The PCM 115 may receive a medium voltage DC power
signal from the cable 160 and supply a low voltage AC power signal
to the motor 120. The medium voltage signal may be greater than one
kV, such as five to ten kV. 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 stepping the voltage from medium to
low, such as less than or equal to one kV. Each converter may be a
single phase active bride 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 step the DC voltage from
medium to low. 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 signal
to the motor controller.
[0020] The motor controller may be a switchboard (i.e., logic
circuit) for simple control of the motor 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.
[0021] The modem and demultiplexer 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 BHA 100. A temperature sensor (or PT sensor) may be
in fluid communication with motor lubricant to ensure that the
motor 120 and downhole controller are being sufficiently cooled.
Multiple temperature sensors may be included in the PCM 115 for
monitoring and recording temperatures of the various electronic
components. A voltage meter and current (VAMP) sensor may be in
electrical communication with the cable 160 to monitor power loss
from the cable. 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 120. Utilizing data from the
sensors, the motor controller may monitor for adverse conditions
and take remedial action before damage to motor 120 occurs.
[0022] The motor 120 may be a two-pole, three-phase, squirrel-cage
induction type. The motor 120 may run at a nominal speed of
thirty-five hundred rpm at sixty Hz. The motor 120 may be filled
with a dielectric, thermally conductive liquid lubricant, such as
motor oil. The motor 120 may be cooled by thermal communication
with the production fluid 35. The motor 120 may include a thrust
bearing (not shown) for supporting the drive shaft 150. In
operation, the motor 120 may rotate the shaft 150, thereby driving
the cleaner 130 and the tractor 140. The drive shaft 150 may be
indirectly rotationally connected to a forward portion 130f of the
cleaner 130 via speed reducer 125f, indirectly rotationally
connected to a reverse portion of the cleaner 130 via speed reducer
125r, and indirectly rotationally connected to the tractor 140 via
speed reducer 135. Alternatively, a slower motor may be used or a
speed of the motor may be controlled so that the motor may be
directly connected to the cleaner 130 and/or the tractor 140 and
one or more of the speed reducers 125f,r, 135 may be omitted
(and/or the reducer 125r may be simply a speed reverser). The motor
120 may further include a lubricant pump (not shown) driven by the
drive shaft 150 and an annulus between the mandrel 145 and the
drive shaft may be used to supply lubricant to the speed reducers.
The mandrel may further have longitudinal ports formed in a wall
thereof to return the lubricant to a reservoir of the pump or vice
versa.
[0023] Each of the speed reducers 125f,r, 135 may be a gearbox
including an input gear (not shown) rotationally connected to the
drive shaft and an output gear (not shown) rotationally connected
to an output shaft 151, 152. Each gearbox may be planetary and
further include an additional stationary gear rotationally
connected to the gearbox housing. Each of the gearboxes 125f,r, 135
may reduce or substantially reduce a rotational speed .omega..sub.d
of the drive shaft. An output rotational speed
.omega..sub.c,|-.omega..sub.c| of the cleaner gearboxes 125f,r may
be less than or equal to one-half or one-third the speed
.omega..sub.d of the drive shaft, such as one-thousand rpm. The
output rotation of the gearbox 125r may also be reversed relative
to the rotation of the drive shaft as indicated by the minus sign.
An output rotational speed .omega..sub.t of the gearbox 135 may be
less than or equal to one-tenth or one-twentieth the speed
.omega..sub.d of the drive shaft, such as fifty to one hundred
rpm.
[0024] The cleaner 130 may include one or more modules, such as a
forward module 130f and a reverse module 130r. Each module 130f,r
may include a housing, a set of brushes 131, and a set of scrapers
132. Each brush 131 may include an array of bristle clusters and a
base having a plurality of holes formed therein. Each hole may
receive a respective one of the bristle clusters. Each bristle
cluster may include a band which bundles together the bristle
cluster and is received or secured in hole. The base may include a
flange projecting laterally from the side thereof operable to mate
with a corresponding groove formed in an outer surface of the
housing, thereby fastening the base to the housing. Each groove may
extend helically along the outer surface of the housing and a set
of grooves may be disposed around the housing. Each base may be
correspondingly helically shaped. The bristles may be made from a
wear resistant metal or alloy, such as steel.
[0025] Each scraper may include a plurality of bodies, a plurality
of blades, and a plurality of cutters. Each scraper body may be a
semi-annular member and may be fastened to the housing in a recess
formed in the outer surface of the housing. The scraper bodies may
also serve as an end to the brush grooves when fastened, thereby
allowing the brushes to be inserted or removed from the grooves by
removing the bodies and preventing the brushes from sliding out of
the grooves when the scraper bodies are installed. A plurality of
the blades may be formed on an outer surface of each body or
fastened thereto. Each blade may be made from a metal or alloy,
such as steel, and a plurality of cutters may be bonded into
respective recesses formed along each blade and at a leading edge
of the blade. The cutters may be made from a wear resistant
material, such as a metal or alloy (i.e., steel) or a ceramic or
cermet (i.e., tungsten carbide). The cutters may be bonded into the
recesses, such as by brazing, welding, soldering, or using an
adhesive. Alternatively, the cutters may be pressed or threaded
into the recesses.
[0026] A sweep of the scraper cutters may correspond to the drift
diameter of the production tubing 10p, such as slightly less than
or equal to the drift diameter. A sweep of the brush bristles may
correspond to the drift diameter of the production tubing 10p, such
as slightly greater than the drift diameter to ensure tight
engagement of the bristles with the tubing inner surface. In this
manner, the scrapers 132 may remove a substantial portion of the
deposit 40 from the production tubing inner surface and then the
brushes 131 may remove all or substantially all of the remaining
deposit. The output shaft 151 of the speed reducer 125r may be
rotationally connected to the reverse module housing and the output
shaft 151 of the speed reducer 125f may be rotationally connected
to the forward module housing. Each of the modules 130f,r may be
longitudinally and radially supported from the mandrel 145 by one
or more bearings 146. The module housings may be counter-rotated to
provide stability and the helical orientation of the brushes of
each module may be reversed (shown) or identical.
[0027] The tractor 140 may include a chassis and a helical screw
141. The screw made be made from the slip resistant material
discussed above. The screw may be molded onto the chassis or
fastened thereto by a flange-slot arrangement discussed above for
the brushes. The chassis and screw 141 may be sized such that an
overall diameter of the tractor (chassis+screw) may correspond to
the drift diameter of the production tubing 10p, such as slightly
greater than the drift diameter to ensure tight engagement of the
screw with an inner surface of the production tubing 10p. The
chassis may be longitudinally and rotationally connected to the
output shaft 152 and the output shaft 152 may be longitudinally and
rotationally supported from the gear reducer housing by bearings
(not shown). Rotation of the tractor 140 by the output shaft 152
may propel the BHA 100 longitudinally down the production tubing
10p due to the engagement of the helical screw 141 with the
production tubing inner surface.
[0028] FIG. 2A is a layered view of the cable 160. FIG. 2B is an
end view of the cable 160. The cable 160 may include an inner core
205, an inner jacket 210, a shield 215, an outer jacket 230, and
armor 235, 240.
[0029] 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. 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 235, 240
and be made from an oil-resistant dielectric material. The armor
may be made from one or more layers 235, 240 of high strength
material (i.e., tensile strength greater than or equal to one
hundred, one fifty, or two hundred kpsi) to support the deployment
weight (weight of the cable and the weight of the BHA 100)) so that
the cable 160 may be used to deploy and remove the BHA 100
into/from the wellbore 5. The high strength material may be a metal
or alloy and corrosion resistant, such as galvanized steel or a
nickel alloy depending on the corrosiveness of the reservoir fluid
35. The armor may include two contra-helically wound layers 235,
240 of wire or strip.
[0030] Additionally, the cable 135r 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 235, 240. The buffer
245 may be tape and may be made from the lubricative material.
[0031] Due to the coaxial arrangement, the cable 160 may have an
outer diameter 250 less than or equal to one and one-quarter
inches, one inch, or three-quarters of an inch. Alternatively, the
cable 160 may include three conductors and conduct three-phase AC
power to the motor 120.
[0032] Additionally, the cable 160 may further include a pressure
containment layer (not shown) made from a material having
sufficient strength to contain radial thermal expansion of the
dielectric layers and wound to allow longitudinal expansion
thereof. The material may be stainless steel and may be strip or
wire. Alternatively, the cable 160 may include only one conductor
and the production tubing 10p may be used for the other
conductor.
[0033] FIGS. 3A-3J illustrate a method of deploying the BHA 100
into a live wellbore 5 and cleaning the wellbore, according to
another embodiment of the present invention.
[0034] To prepare for insertion of the BHA 100 into the live
wellbore 5, a service truck 350 may be deployed to the wellsite.
The BHA 100, a lubricator 300, and a blowout preventer (BOP) stack
315 may be transported to the wellsite by the truck 350 or a second
truck (not shown). The service truck may include a control room
355, a winch 360 having the cable 160 wrapped therearound, a boom
365, a generator 370, and a controller 375. The generator may be
diesel-powered and provide alternating current (AC) power. The
truck controller 375 may include a transformer (not shown) for
stepping the voltage of the AC power signal from the generator 370
to a medium voltage signal. The truck controller may further
include a rectifier for converting the medium voltage AC signal to
a medium voltage direct current (DC) power signal for transmission
downhole via the cable 160. The truck controller 375 may be in
electrical communication with the cable 160 via leads and an
electrical coupling (not shown), such as brushes or slip rings, to
allow power transmission through the cable while the winch 360
winds and unwinds the cable. The truck controller 375 may further
include a data modem (not shown) and a multiplexer (not shown) for
modulating and multiplexing a data signal to/from the downhole
controller with the DC power signal. The winch 360 may include an
electric or hydraulic motor (not shown) and a drum rotatable by the
motor for winding or unwinding of the cable 160.
[0035] Production of the wellbore 5 may be halted by closing the
master valve 51. The choke and/or a wing valve (not shown) may be
closed. The swab valve 53 may be closed or already closed. The cap
54 may be removed. The BOP stack 315 may be connected to the swab
valve 53, such as by fastening. The BOP stack 315 may include one
or more ram BOPs (only one shown), such as two. The first ram BOP
may include a pair of blind-shear rams (or separate blind rams and
shear rams) capable of cutting the cable when actuated and sealing
the bore, and a second ram BOP may include a pair of cable rams for
sealing against an outer surface of the cable 160 when actuated.
The truck 350 may further include a hydraulic power unit (HPU, not
shown) for operating the BOP stack 315. The BOP stack 315 may be
closed after installation.
[0036] Once the BOP stack 315 has been installed, the BHA 100 may
be inserted into the lubricator 300. The lubricator 300 may include
a tool housing 305 and a seal head 310. The tool housing 305 may be
of sufficient length to contain the BHA 100. The seal head 310 may
include one ore more grease injector heads and a packoff. The truck
350 may include a grease pump (not shown) in fluid communication
with the injector head via a grease conduit (not shown). The
packoff may also be in fluid communication with the grease pump for
energizing thereof. The seal head 310 may be operable to maintain a
seal with the cable 160 while allowing the cable 160 to slide in or
out of the tool housing 305. The lubricator components 305, 310 may
be connected, such as by flanged connections (not shown). An inner
diameter of the tool housing 305 may correspond to the drift
diameter of the production tubing 10p, such as equal to or greater
than the drift diameter.
[0037] The cable 160 may then be inserted through the seal head 310
and fastened to the cablehead 105. The boom 365 may be used to
hoist the lubricator 300 and the BHA 100 onto the BOP stack 315 and
the tool housing 305 may then be fastened to the BOP stack 315. The
seal head packoff may then be engaged with the cable 160 by
operating the grease pump. The BOP stack 315, swab valve 53, and
master valve 51 may then be opened. The BHA 100 may be energized,
thereby operating the motor 120, tractor 140, and cleaner 130. The
truck controller 375 may be in communication with the winch motor
and operable to unwind the cable at a predetermined rate and/or to
maintain a predetermined tension in the cable to control descent of
the BHA 100. The BHA 100 may then be lowered and/or propelled
through the tree 50 and into the wellbore 5. The brushes 131 and
scrapers 132 may engage the deposit 40 and remove the deposit from
an inner surface of the production tubing 10p as the BHA 100
travels down the production tubing.
[0038] Once a length of the production tubing 10p has been cleaned,
cleaning may be halted, such as by sending an instruction signal to
the motor controller to shutoff power to the motor or shutting off
power to the BHA 100. The choke 55 and/or wing valve may be opened.
The motor 120 may then be reversed, such as by sending an
instruction signal to the motor controller and/or reversing
polarity of the DC power signal. The tractor 140 may then propel
the BHA 100 upward through the production tubing 10p and/or the
winch 360 may be operated to pull the BHA. The tractor 140 may act
as a swabbing tool as the BHA 100 travels along the production
tubing 10p, thereby pumping deposit laden wellbore fluid 335 upward
into the tree 50 and through the choke 55. The existing production
equipment may be capable of handling the deposit laden production
fluid 355 or a tank (not shown) may be connected to the choke 55
for storage of the deposit laden production fluid. Alternatively,
the motor 120 may be shut off during the swabbing. Alternatively,
forward operation of the motor 120 may be maintained during
swabbing and the winch 360 may be used to pull the BHA 100 along
the production tubing 10p while dragging against the tractor
140.
[0039] Once the BHA 100 has completed the swabbing, the motor may
again be reversed and cleaning of the production tubing 10p may be
continue. The cleaning/swabbing cycle may repeated until the
production tubing 10p is clean (two cycles shown). The length of
production tubing cleaned/swabbed during each cycle may be
determined based on the specifics of the wellbore 5 and/or
performance of the BHA 100. Once the production tubing 10p is
clean/swabbed, the BHA 100 may be retrieved into the tool housing
305. The master valve 51, swab valve 53, and BOP stack 315 may then
be closed. The tool housing 305 may then be unfastened from the BOP
stack 315 and the BHA 100 and lubricator 300 may be removed from
the BOP stack 315 using the boom 365. The BOP stack 315 may then be
removed from the swab valve 53 and the cap 54 reinstalled. The
wellbore 5 may then be placed back into production. Advantageously,
deployment of the BHA 100 using the lubricator 300 allows the
production tubing 10p to be cleaned while the formation 25 is
alive.
[0040] FIG. 4A illustrates a BHA 400, according to another
embodiment of the present invention. FIG. 4B illustrates a cable
460 for deploying the BHA 400. The forward cleaner module has been
removed to maintain the drawing size but may be included. The cable
460 may include a fluid conduit, such as a tube 407. The tube 407
may be disposed in a bore formed in the inner core 405 or the inner
core may be wrapped along the tube. The tube 407 may be made from a
dielectric polymer or a metal or alloy having a dielectric coating.
A hydraulic cable swivel 405s may replace the swivel 105s and be in
fluid communication with the tube 407. Each of the guide and the
PCM may have a fluid conduit, such as a tube 408, extending through
a housing thereof. A hydraulic shaft swivel 470 may be added
between the PCM and the motor and the drive shaft 450 may be
received by the shaft swivel 470. The drive shaft 450 may have a
bore formed at least substantially therethrough. The swivel 470 may
provide fluid communication between the tube 408 and the drive
shaft bore.
[0041] A fluid injector 475 may be added between the cleaner and
the tractor speed reducer. The fluid injector 475 may include a
hydraulic swivel in communication with the shaft bore and a fluid
circuit having one or more check valves and one or more nozzles
operable to spray cleaning fluid 480 from the shaft bore toward the
cleaner. The check valves may be operable to allow flow from the
shaft bore through the nozzles and prevent reverse flow
therethrough. The service truck 350 may further include a cleaning
fluid reservoir (not shown) and a pump in fluid communication with
the fluid reservoir and the tube 407. During cleaning, the pump may
be operated to inject the cleaning fluid 480 through the tube 407.
The fluid 480 may continue through the cable swivel 405s, the tube
408, the shaft swivel 470, and to the injector 475. The cleaning
fluid 480 may be discharged form the injector nozzles through the
scrapers and the brushes, thereby cleaning deposit cuttings from
the scrapers and brushes, cooling the scrapers and brushes, and
lubricating the scrapers and brushes. The cleaning fluid 480 may be
a liquid lubricant, such as mineral oil, or a liquid cleaning
agent, such as mineral spirits or acid (i.e., acetic acid).
[0042] The choke 55 and/or wing valve may be opened during cleaning
to receive the injected fluid and/or production fluid 35 displaced
by the injected fluid. Further, injection of the cleaning fluid 480
may transport deposit cuttings from the wellbore 5, thereby
reducing or obviating the need for swabbing. Alternatively, the
swabbing may be performed as discussed above.
[0043] FIG. 5 illustrates a BHA 500, according to another
embodiment of the present invention. Instead of pumping the
cleaning fluid 480 through the cable 460, the cable 160 may be
deployed with a coiled tubing string 560. Prior to deployment, the
cable 160 may be inserted or pumped through the coiled tubing 560.
An additional truck (not shown) may carry the coiled tubing reel
and injector to the wellsite and a stripper (not shown) may replace
the lubricator 300. The BHA 500 may include a coiled tubing head
505 connected to the PCM. The anti-rotation guide may be omitted as
the coiled tubing 560 may be used to rotationally restrain the BHA
500. Alternatively, the anti-rotation guide may be included or a
centralizer may be included. A seal head (not shown) may be used at
a reel end of the coiled tubing to allow the cleaning fluid 480 to
be pumped into an annulus formed between the coiled tubing 560 and
the cable 160. The cleaning fluid 480 may be received by a fluid
conduit, such as a tube 508, extending through a housing of the
PCM. The fluid conduit 508 may deliver the fluid to the shaft
swivel 470.
[0044] Alternatively, any of the BHAs 100, 400, 500 may be deployed
to clean other types of tubular strings, such as to remove residual
cement and/or mud cake from a casing or liner string.
Alternatively, the formation 25 may be killed before deployment of
the BHAs by pumping a heavy weight kill fluid into the production
tubing 10p. Alternatively, any of the BHAs 100, 400, 500 may be
deployed into a subsea wellbore having a horizontal or vertical
subsea tree or having a land-type completion.
[0045] 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.
* * * * *