CABLE DEPLOYED DOWNHOLE TUBULAR CLEANOUT SYSTEM

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.

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Description
BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to a cable deployed downhole tubular clean out system.

2. Description of the Related Art

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.

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).

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

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.

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

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.

FIG. 1 illustrates a prior art producing wellbore obstructed by deposit buildup in the production tubing.

FIG. 2 illustrates a cable deployed bottomhole assembly (BHA) for performing a cleanout operation, according to one embodiment of the present invention.

FIG. 2A is a layered view of the cable. FIG. 2B is an end view of the cable.

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.

FIG. 4A illustrates a BHA, according to another embodiment of the present invention. FIG. 4B illustrates a cable for deploying the BHA.

FIG. 5 illustrates a BHA, according to another embodiment of the present invention.

 DETAILED DESCRIPTION

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.

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.

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.

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.

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.

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.

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.

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 ωd of the drive shaft. An output rotational speed ωc,|−ωc| of the cleaner gearboxes 125f,r may be less than or equal to one-half or one-third the speed ωd 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 ωt of the gearbox 135 may be less than or equal to one-tenth or one-twentieth the speed ωd of the drive shaft, such as fifty to one hundred rpm.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

Patent History
Publication number: 20120211229
Type: Application
Filed: Feb 18, 2011
Publication Date: Aug 23, 2012
Inventors: Lance I. Fielder (Sugar Land, TX), Evan Sheline (Houston, TX), Matthew Crowley (Houston, TX), Bruce H. Storm, JR. (Houston, TX)
Application Number: 13/031,044
Classifications
Current U.S. Class: Cleaning Or Unloading Well (166/311); Brushing, Scraping, Cutting Or Punching-type Cleaners (166/170)
International Classification: E21B 37/00 (20060101);