Abstract:
A method of deploying a downhole tool into a wellbore includes: lowering a cable into the wellbore; after lowering the cable, engaging a mold with an outer surface of the cable; injecting sealant into the mold and into armor of the cable, thereby sealing a portion of the cable; lowering the downhole tool to a deployment depth using the cable; engaging a seal with the sealed portion of the cable; and operating the downhole tool using the cable.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. provisional Pat. App. No. 61/487,945, filed May 19, 2011, which is herein incorporated by reference in its entirety. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments of the present invention generally relate to a seal around a braided cable. 
     2. Description of the Related Art 
     In the oil and gas industry, the term wireline typically refers to a cable used by operators of oil and gas wells to lower downhole tools, such as logging sensors, into a wellbore for purposes of well intervention and reservoir evaluation. The wireline may be a braided line and may contain an inner core of insulated wires, which provide power to equipment located at the end of the wireline, and provides a pathway for electrical telemetry for communication between the surface and equipment at the end of the wireline. The wireline resides on the surface, wound around a large diameter (e.g., 3 to 10 feet diameter) spool of a winch. The winch may be portable (e.g., on the back of a truck) or a semi-permanent part of the drilling rig. The winch may include a motor and drive train operable to turn the spool, thereby raising and lowering the tools into and out of the well. 
     A pressure control head is also employed during wireline operations to contain pressure originating from the wellbore. However, braided cable presents problems as pressure is likely to communicate between and under the multiple strands of the braid. For this reason, the pressure control head includes a grease injector for injecting thick grease into and around the cable in conjunction with a stuffing box for sealing against an outer surface of the cable while allowing the wireline to slide through. However, if a more semi-permanent stationary seal is required around the braided cable (for example, in the deployment of a power cable suspended electric submersible pump (ESP) system) continuous grease injection may not be convenient. 
     SUMMARY OF THE INVENTION 
     Embodiments of the present invention generally relate to a seal around a braided cable. In one embodiment, a method of deploying a downhole tool into a wellbore includes: lowering a cable into the wellbore; after lowering the cable, engaging a mold with an outer surface of the cable; injecting sealant into the mold and into armor of the cable, thereby sealing a portion of the cable; lowering the downhole tool to a deployment depth using the cable; engaging a seal with the sealed portion of the cable; and operating the downhole tool using the cable. 
     In another embodiment, a cable for deploying and operating a downhole tool includes: one or more electrical conductors extending a length of the cable; a jacket disposed around each conductor and extending the cable length; one or more layers of armor disposed around the jackets; sealant impregnated in the armor and extending only a portion of the cable length. The cable length is greater than or equal to five hundred feet. A length of the sealed portion is less than or equal to one-tenth of the cable length. 
    
    
     
       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. 
         FIGS. 1A-1C  illustrate deployment of an electric submersible pump (ESP) into a wellbore, according to one embodiment of the present invention.  FIG. 1A  illustrates the ESP and a stuffing box being lowered toward a production tree.  FIG. 1B  illustrates installation of a mold around the cable.  FIG. 1C  illustrates the ESP deployed and operating. 
         FIGS. 2A-2D  illustrate molding a portion of a cable with sealant.  FIG. 2A  illustrates the cable.  FIG. 2B  illustrates the mold assembled around the cable.  FIG. 2C  illustrates injection of sealant into the mold.  FIG. 2D  illustrates a portion of the cable impregnated by the sealant. 
         FIGS. 3A-3C  illustrate deployment of the ESP into the wellbore, according to another embodiment of the present invention.  FIG. 3A  illustrates a mold connected to the blowout preventer (BOP).  FIG. 3B  illustrates the ESP and the stuffing box being lowered toward the tree.  FIG. 3C  illustrates the ESP deployed and operating. 
         FIGS. 4A-4D  illustrate molding a portion of the cable with sealant.  FIG. 4A  is an enlargement of a portion of  FIG. 3A  illustrating the cable extending through the mold.  FIG. 4B  illustrates seals of the mold engaged with the cable.  FIG. 4C  illustrates injection of sealant into the mold.  FIG. 4D  illustrates a portion of the cable impregnated by the sealant. 
     
    
    
     DETAILED DESCRIPTION 
       FIGS. 1A-1C  illustrate deployment of an electric submersible pump (ESP)  105  into a wellbore  5 , according to one embodiment of the present invention.  FIG. 1A  illustrates the ESP  105  and a stuffing box  115  being lowered toward a production tree  50 . The ESP  105  may be part of an artificial lift system (ALS)  100 . The ALS  100  may include the ESP  105 , a blowout preventer (BOP)  110  or BOP stack (only one BOP shown), the stuffing box  115 , and a launch and recovery system (LARS)  120 . 
     The wellbore  5  has been drilled from a surface  1   s  of the earth into a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir  25 . A string of casing  10   c  has been run into the wellbore  5 , hung from a wellhead  15 , and set therein with cement (not shown). The casing  10   c  has been perforated  30  to provide to provide fluid communication between the reservoir  25  and a bore of the casing  10   c . A string of production tubing  10   p  extends from the wellhead  15  to the reservoir  25  to transport production fluid  35  ( FIG. 1C ) from the reservoir  25  to the surface  1   s . A packer  12  has been set between the production tubing  10   p  and the casing  10   c  to isolate an annulus  10   a  formed between the production tubing and the casing from production fluid  35 . 
     The 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 (not shown), and a production choke  55 . Production fluid  35  from the reservoir  25  may enter a bore of the production tubing  10   p , travel through the tubing bore to the surface  1   s . 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). The reservoir  25  may be dead due to depletion or kill fluid or the reservoir may be live and isolated by a subsurface safety valve (not shown), thereby obviating the need for a lubricator (not shown). Alternatively, the wellbore  5  may be live and the lubricator may be employed to lower the ESP into the wellbore. 
     To prepare for insertion of the ESP  105  into the wellbore  5 , one or more trucks (not shown) may deliver the ALS system  100  to the wellsite. The LARS  120  may include a control room  121 , a winch  124  having cable  130  wrapped therearound, a boom  125 , a generator  122 , a controller  123 , and a skid frame  126 . The generator  122  may be diesel-powered and provide alternating current (AC) power. The LARS controller  123  may include a transformer (not shown) for stepping the voltage of the AC power signal from the generator  122  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 three to ten kV. The LARS controller  123  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  130 . The LARS controller  123  may be in electrical communication with the cable  130  via leads and an electrical coupling (not shown), such as brushes or slip rings, to allow power transmission through the cable while the winch  124  winds and unwinds the cable  130 . The LARS controller  123  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  124  may include an electric or hydraulic motor (not shown) and a drum rotatable by the motor for winding or unwinding of the cable  130 . 
     The ESP  105  may include an electric motor  101 , a power conversion module (PCM)  102 , 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 rotationally connected, such as by flanged or threaded connections. The cablehead  107  may include a cable fastener (not shown), such as slips or a clamp for longitudinally connecting the ESP to the cable  130 . Since the power signal may be DC, the cable  130  may only include two conductors arranged coaxially (discussed more below). 
     The cable  130  may be longitudinally coupled to the cablehead  107  by a shearable connection (not shown). The cable  130  may be sufficiently strong so that a margin exists between the 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  105  become trapped in the wellbore  5 , such as by jamming of the isolation device  106  or buildup of sand, the cable  130  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  105 . 
     The cablehead  107  may also include leads (not shown) extending therethrough and through the isolation device  106 . The leads may provide electrical communication between the conductors of the cable  130  and conductors of the flat cable  108 . The flat cable  108  may extend along the pump  104  and the seal section  102  to the PCM  102 . The flat cable  108  may have a low profile to account for limited annular clearance between the components  103 ,  104  and the production tubing  10   p . Since the flat cable  108  may conduct the DC signal, the flat cable may only require two conductors (not shown) and may only need to support its own weight. The flat cable  108  may be armored by a metal or alloy. 
     The 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 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  35 . 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 induction motor may be a two-pole, three-phase, squirrel-cage induction type and may run at a nominal speed of thirty-five hundred rpm at sixty Hz. The SRM motor may include a multi-lobed rotor made from a magnetic material and a multi-lobed stator. Each lobe of the stator may be wound and opposing lobes may be connected in series to define each phase. For example, the SRM motor may be three-phase (six stator lobes) and include a four-lobed rotor. The BLDC motor may be two pole and three phase. The BLDC motor may include the stator having the three phase winding, a permanent magnet rotor, and a rotor position sensor. The permanent magnet rotor may be made of one or more rare earth, ceramic, or 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 PCM  102  may include a power supply, a motor controller (not shown), a modem (not shown), and demultiplexer (not shown). The power supply may include one or more DC/DC converters, each converter including an inverter, a transformer, and a rectifier for converting the DC power signal into an AC power signal and reducing the voltage from medium to low. Each converter may be a single phase active bridge circuit as discussed and illustrated in PCT Publication WO 2008/148613, which is herein incorporated by reference in its entirety. The power supply may include multiple DC/DC converters in series to gradually reduce the DC voltage from medium to low. For the SRM and BLDC motors, the low voltage DC signal may then be supplied to the motor controller. For the induction motor, the power supply may further include a three-phase inverter for receiving the low voltage DC power signal from the DC/DC converters and outputting a three phase low voltage AC power signal to the motor controller. 
     For the induction motor, 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. 
     For the SRM or BLDC motors, the motor controller 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. The output signal may be stepped, trapezoidal, or sinusoidal. The BLDC motor controller may be in communication with the rotor position sensor and include a bank of transistors or thyristors and a chopper drive for complex control (i.e., variable speed drive and/or soft start capability). The SRM motor controller may include a logic circuit for simple control (i.e. predetermined speed) or a microprocessor for complex control (i.e., variable speed drive and/or soft start capability). The SRM motor controller may use one or two-phase excitation, be unipolar or bi-polar, and control the speed of the motor by controlling the switching frequency. The SRM motor controller may include an asymmetric bridge or half-bridge. 
     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 ESP  105 . A pressure and temperature (PT) sensor may be in fluid communication with the reservoir fluid  35  entering an inlet of the pump  104 . A gas to oil ratio (GOR) sensor may also be in fluid communication with the reservoir fluid  35  entering the pump inlet. A second PT sensor may be in fluid communication with the reservoir fluid  35  discharged from an outlet of the pump  104 . A temperature sensor (or PT sensor) may be in fluid communication with the lubricant to ensure that the motor  101  and PCM  102  are being sufficiently cooled. Multiple temperature sensors may also be included in the PCM  102  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  130  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  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 . Utilizing data from the sensors, the motor controller may monitor for adverse conditions, such as pump-off, gas lock, or abnormal power performance and take remedial action before damage to the pump  104  and/or motor  101  occurs. 
     The seal section  103  may isolate the reservoir fluid  35  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  35 . The seal section  103  may rotationally 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 may be standard type, static gas separator type, or rotary gas separator type depending on the GOR of the production fluid  35 . The standard type inlet may include a plurality of ports allowing reservoir fluid  35  to enter a lower or first stage of the pump  104 . The standard inlet may include a screen to filter particulates from the reservoir fluid  35 . The static gas separator type may include a reverse-flow path to separate a gas portion of the reservoir fluid  35  from a liquid portion of the reservoir fluid  35 . 
     The isolation device  106  may include a packer, an anchor, and an actuator. The actuator may be operated mechanically by articulation of the cable  130 , 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 formed above the packer for discharging the pressurized reservoir fluid into the production tubing  10   p . Once the ESP  105  has reached deployment depth, the isolation device actuator may be operated, thereby setting the anchor and expanding the packer against the production tubing  10   p , isolating the pump inlet from the pump outlet, and rotationally connecting the ESP  105  to the production tubing. The anchor may also longitudinally support the ESP  105 . 
     Additionally, the isolation device  106  may include a bypass vent (not shown) for releasing gas separated by the pump inlet 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  130  to facilitate the delivery of the ESP  105 , 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 rotationally and longitudinally connected to the pump shaft, such as by a key. The diffuser may be longitudinally and rotationally coupled 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  35  and flow through the stationary diffuser may convert a portion of the velocity into pressure. The pump  104  may deliver the pressurized reservoir fluid  35  to the isolation device bore. 
     Alternatively, the pump  104  may be a high speed compact pump discussed and illustrated at FIGS. 1C and 1D of U.S. patent application Ser. No. 12/794,547, filed Jun. 4, 2010, which is herein incorporated by reference in its entirety. High speed may be greater than or equal to ten thousand, fifteen thousand, or twenty thousand revolutions per minute (RPM). 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 rotationally connected to the motor drive shaft and be rotated by operation of the motor. As the rotor is rotated, the production fluid  35  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. 
     The tree cap may be removed from the tree  50 . The BOP  110  may be connected to the swab valve  53 , such as by fastening. The BOP  110  may include one or more ram BOPS, 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  130  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  130  when actuated. The LARS  120  may further include a hydraulic power unit (HPU, not shown) for operating the BOP stack  110 . Once the BOP  110  has been installed, the cable  130  may then be inserted through the stuffing box  115  and fastened to the cablehead  105 . The boom  125  may be used to hoist the ESP and stuffing box over the BOP  110 . The swab valve  53  and master valve  51  may then be opened. The ESP  105  may be lowered through the tree  50  and into the wellbore until the stuffing box  115  engages the BOP  110 . Lowering may be halted and the stuffing box  115  may be fastened to the BOP  110 , such as by a flanged connection. Lowering of the ESP  105  into the wellbore  5  may resume until the ESP is proximately above deployment depth. 
       FIG. 1B  illustrates installation of a mold  200  around the cable  130 . The winch  124  may be locked with the ESP  105  in the wellbore  5  proximately above deployment depth. Alternatively, the isolation device  106  may be set to support the ESP  105 . The mold  200  may be assembled around the cable  130  above the stuffing box  115 . 
       FIGS. 2A-2D  illustrate molding a portion  150  of the cable  130  with sealant  250 .  FIG. 2A  illustrates the cable  130 . The cable  130  may include an inner core  131 , an inner jacket  132 , a shield  133 , an outer jacket  136 , and one or more layers  138   i,o  of armor. 
     The inner core  131  may be the first conductor and made from an electrically conductive material, such as aluminum, copper, or alloys thereof. The inner core  131  may be solid or stranded (shown). The inner jacket  132  may electrically isolate the core  131  from the shield  133  and be made from a dielectric material, such as a polymer. The shield  133  may serve as the second conductor and be made from the electrically conductive material. The shield  133  may be tubular (shown), braided, or a foil covered by a braid. The outer jacket  136  may electrically isolate the shield  133  from the armor  138   i,o  and be made from an oil-resistant dielectric material. The armor may be made from one or more layers  138   i,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 deployment weight (weight of the cable  130  and the weight of the ESP  105 )) so that the cable  130  may be used to deploy and remove the ESP  105  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  138   i,o  of wire or strip. 
     Additionally, the cable  130  may include a sheath  135  disposed between the shield  133  and the outer jacket  136 . The sheath  135  may be made from lubricative material, such as polytetrafluoroethylene (PTFE) or lead, and may be tape helically wound around the shield  133 . If lead is used for the sheath  135 , a layer of bedding  134  may insulate the shield  133  from the sheath and be made from the dielectric material. Additionally, a buffer  137  may be disposed between the armor layers  138   i,o . The buffer  137  may be tape and may be made from the lubricative material. The buffer  137  may be perforated to allow sealant flow to the inner armor layer  138   i    
     Due to the coaxial arrangement, the cable  130  may have an outer diameter less than or equal to one and one-quarter inches, one inch, or three-quarters of an inch. Alternatively, the conductors  131 ,  133  may be eccentrically arranged and/or the cable  130  may include three or more conductors, such as three, and conduct three-phase AC power to the motor  101  (obviating the PCM  102 ). Alternatively, the cable  130  may include only one conductor and the production tubing  10   p  may be used for the other conductor. 
       FIG. 2B  illustrates the mold  200  assembled around the cable  130 . The mold  200  may be delivered to the wellsite by a service truck (not shown). The service truck may include a reaction injector and a crane or platform to lift the mold to a top of the stuffing box. The reaction injector may include a pair of supply tanks each having a liquid reactive component (aka resin and hardener) stored therein. The supply tanks or the components may or may not be heated. The service truck may further include a pair of feed pumps, each having an inlet connected to a respective supply tank. An outlet of each supply pump may be connected to a mix head and an outlet of the mix head may connect to the mold  200 . The service truck may further include an HPU for powering the supply pumps. The service truck may further include a controller for proportioning the feed pumps. The feed pumps may be operated to simultaneously supply the liquid reactive components to the mix head. The mix head may impinge the liquid components to begin polymerization of the sealant mixture  250 . The sealant mixture  250  may continue from the mix head into the mold  200 . 
     Alternatively, the service truck may include an injector, a crane or platform to lift the injector and the mold to a top of the stuffing box, and an HPU to power the injector. The injector may include a hopper, a barrel, a driver, and a heater. The heater may surround the mold side of the barrel. The driver may be a rotating screw disposed in the barrel. The screw may have a feed section, transition section, and a metering section. The feed section may receive sealant pellets from the hopper and convey them to the transition section. The transition section may compress the pellets into a molten sealant and pump the molten sealant to the metering section. The screw may be supported by a hydraulic ram that is displaced away from the mold by the sealant feed through the screw. The hydraulic ram may then reverse to inject the molten sealant into the mold. Alternatively, the driver may be a hydraulic plunger and a torpedo spreader. 
     The mold  200  may include a split housing  205  and upper  210   u  and lower  210   b  seals ( FIG. 1B ). The housing  205  may include a pair of mating semi-tubular segments  205   a,b . Each housing segment  205   a,b  may have radial couplings, such as flanges  208 , formed therealong and half of a longitudinal coupling  211  formed at one or both longitudinal ends thereof. The radial flanges  208  of each housing segment  205   a,b  may be connected to the mating radial flanges by fasteners  207 , such as bolts and nuts. A gasket  209  may be disposed in a groove formed in one of the housing segments for sealing the radial connection. Alternatively, the radial couplings may instead be a hinge and latch. Each seal  210   u,b  may include a pair of mating semi-annular segments. One segment of each seal  210   u,b  may include a coupling (not shown) formed at ends thereof, such as a ball and the other segment may include a mating coupling, such as a socket, so that the couplings mate when the housing  205  is assembled. 
     An inner diameter of the mold housing  205  may be slightly greater than an outer diameter of the cable  130 , thereby forming an annulus  212  between the mold housing and the cable. The housing  205  may have a sprue  206  formed through a wall of one of the segments  205   a,b  and in fluid communication with the annulus  212 . An inner diameter of the mold seals  210   u,b  may be slightly less than an outer diameter of the cable  130  so that the mold seals engage an outer surface of the cable when the mold  200  is assembled. 
     The service truck crane/platform may lift each of the housing segments  205   a,b  on to the stuffing box  115 . The housing segments  205   a,b  may be radially assembled around the cable  130  using the fasteners  207 . The assembled housing  205  may then be connected to the stuffing box  115  via the flange  211 . Alternatively, the housing  205  may just rest on the stuffing box  115 . 
       FIG. 2C  illustrates injection of sealant  250  into the mold  200 . The sealant  250  may be a polymer, such as a thermoplastic, elastomer, copolymer, or thermoset, such as polyisoprene, polybutadiene, polyisobutylene, polychloroprene, butadiene-styrene rubber, styrene-butadiene copolymer (thermoplastic elastomer), butadiene-acrylonitrile, acrylonitrile butadiene styrene (ABS), silicone, ethylene propylene diene monomer (EPDM) rubber, or polyurethane. 
     Once the mold  200  has been assembled around the cable  130 , the mix head may be lifted to the mold  200  by the service truck crane or the service truck platform may lift the reaction injector to the mold  200 . The mix head may be connected to the sprue  206 . The supply pumps may then be operated to pump the liquid reactants to the mix head. The sealant mixture  250  may continue from the mix head into the mold  200 . Air displaced by the sealant mixture  250  may vent from the mold via leakage through and along the armor  138   i,o . The sealant mixture  250  may flow around and along the annulus  212  until the sealant mixture  250  encounters the seals  210   u,b . Pressure in the mold  200  may increase and the sealant mixture  250  may be forced into the armor  138   i,o . Sealant penetration into the cable  130  may be stopped by the outer jacket  136 . Pumping of the sealant mixture  250  may continue until the mold  200  is filled. The mold  200  may be heated by exothermic polymerization of the mixture  250 . A melting temperature of the mold seals  210   u,b , gasket  209 , and outer jacket  136  may be suitable to withstand the exothermic reaction. 
       FIG. 2D  illustrates a portion  150  of the cable  130  impregnated by the sealant  250 . Once the sealant  250  has cured and cooled to at least a point sufficient to maintain structural integrity, the mix head may be disconnected from the mold  200  and the mold  200  may be disconnected from the stuffing box  115 . The fasteners  207  may then be removed. The service truck may further include a hydraulic spreader. The spreader may be connected to the mold  200  and operated to separate the mold. The service truck may stow the mold  200  and mix head and leave the wellsite. 
     A length of the sealed portion  150  may be greater than or equal to a length of a seal of the stuffing box  115 . For example, the sealed portion length may be greater than or equal to one foot, three feet, five feet, six feet, or ten feet. A length of the cable  130  may be greater than or equal to five hundred or one thousand feet. The sealed portion length may be substantially less than a length of the cable  130 , such as less than or equal to one-tenth, one hundredth, or one thousandth the cable length. An outer diameter of the sealed portion  150  may be slightly greater than an outer diameter of the rest of the cable  130 . Alternatively, the outer diameter of the sealed portion  150  may be equal to an outer diameter of the rest of the cable  130 , such as by eliminating the annulus  212  or trimming the sealed portion. 
       FIG. 1C  illustrates the ESP  105  deployed and operating. The winch  124  may then be unlocked and operated to lower the ESP  105  to deployment depth. As the ESP  105  is lowered, the sealed portion  150  may be lowered into alignment with the stuffing box seal. The isolation device  106  may then be set to engage the production tubing  10   p  and the stuffing box  115  may be operated to engaged the sealed portion  150 . The ESP  105  may then be operated to pump production fluid  35  from the wellbore  5  to the tree  50  and through the tree to the surface separation, treatment, and storage equipment. 
       FIGS. 3A-3C  illustrate deployment of the ESP  105  into the wellbore,  5  according to another embodiment of the present invention.  FIG. 3A  illustrates a mold  300  connected to the BOP  110 . The service truck discussed above in conjunction with the mold  200  may deliver the mold  300  to the wellsite. The tree cap may be removed from the tree  50 . The BOP  110  may be connected to the swab valve  53 . The swab valve  53  and master valve  51  may then be opened. The cable  130  may then be inserted through the mold  300 . A cablehead (not shown) may be fastened to the cable  130  and used to lift the mold  300  over the BOP  110  and lower the mold on to the BOP. The mold  300  may then be fastened to the BOP  110 . Alternatively, the platform/crane of the service truck may be used to lift the mold  300  on to the BOP  110 . The mold  300  may then be fastened to the BOP  110  and the cable  130  may be inserted through the mold and the tree  50  into the wellbore  5 . The cable  130  may then be lowered into the wellbore  5  until proximately above the ESP deployment depth. 
       FIGS. 4A-4D  illustrate molding a portion  150  of the cable  130  with the sealant  250 .  FIG. 4A  is an enlargement of a portion of  FIG. 3A  illustrating the cable  130  extending through the mold  300 . The mold  300  may include a runner  305 , and upper  315   u  and lower  315   b  stuffing boxes. The runner  305  may include one or more tubular sections  305   u,b  connected by a coupling  308 . Each section  305   u,b  may include a housing  309  and an insert  307 . An annular coupling  308  may connect to each of the runner sections, such as by a threaded connection. Each housing  309  may also connect to a housing  316  of a respective stuffing box  315   u,b , such as by a threaded connection. The coupling  308  may have a shoulder formed therein for receiving an end of each insert  307  and each stuffing box housing  316  may have a shoulder for receiving the other end of each insert. An inner diameter of the inserts  307  may be slightly greater than an outer diameter of the cable  130 , thereby forming an annulus  312  between the inserts  307  and the cable  130 . The coupling  308  may have a sprue  306  formed through a wall thereof in fluid communication with the annulus  312 . 
     Each stuffing box  315   u,b  may include a tubular housing  316 , a seal  320 , a piston  318 , and a spring  317 . Each housing  316  may include one or more sections and each housing section may be connected, such as by threads. A port  319  may be formed through the housing in communication with the piston  318 . The port  319  may be connected to the service truck HPU via a hydraulic conduit (not shown). When operated by hydraulic fluid, the piston  318  may longitudinally compress the seal  320 , thereby radially expanding the seal  320  inward into engagement with the cable  130 . The spring  317  may bias the piston  318  away from the seal  320 . Alternatively, the spring  317  may be omitted and bias from the seal  320  may be used to disengage the seal from the cable  130 . 
       FIG. 4B  illustrates seals  320  of the mold  300  engaged with the cable  130 . Once the cable  130  has been lowered to a depth proximately above the ESP deployment depth, hydraulic fluid may be supplied to the stuffing box ports  319 , thereby engaging the stuffing box seals  320  with the cable  130 . 
       FIG. 4C  illustrates injection of sealant  250  into the mold  300 . Once the seals  320  engage the cable  130 , the mix head may be connected to the sprue  306 . The sealant mixture  250  may then be pumped into the mold  300 . Air displaced by the sealant mixture  250  may vent from the die via leakage through and along the armor  138   i,o . The sealant mixture  250  may flow around and along the annulus  312  until the sealant mixture  250  encounters the seals  320 . Pressure in the mold  300  may increase and the sealant mixture  250  may be forced into the armor  138   i,o . Sealant penetration into the cable  130  may be stopped by the outer jacket  136 . Pumping of the sealant mixture  250  may continue until the mold  300  is filled. 
       FIG. 4D  illustrates a portion  150  of the cable  130  impregnated by the sealant  250 . Once the sealant  250  has cured and cooled to at least a point sufficient to maintain structural integrity, hydraulic pressure may be relieved from the ports  319 . The winch  124  may then be operated to pull the sealed portion  150  free from the mold  300  and may continue winding the cable  130  until an end of the cable is above the mold  300 . The mix head may be disconnected from the mold  300 . The mold  300  may be disconnected from the BOP  110 . The service truck may stow the mold  300  and mix head and leave the wellsite. 
       FIG. 3B  illustrates the ESP  105  and the stuffing box  115  being lowered toward the tree  50 . The cable  130  may then be inserted through the stuffing box  115  and fastened to the cablehead  105 . The boom  125  may be used to hoist the ESP  105  and stuffing box  115  over the BOP  110 . The ESP  105  may be lowered through the tree  50  and into the wellbore  5  until the stuffing box  115  engages the BOP  110 . Lowering may be halted and the stuffing box  115  may be fastened to the BOP  110 . Lowering of the ESP  105  into the wellbore  5  may resume until the ESP is at the deployment depth. 
       FIG. 3C  illustrates the ESP  105  deployed and operating. As the ESP  105  is lowered to the deployment depth, the sealed portion  150  may be lowered into alignment with the stuffing box seal. The isolation device  106  may then be set to engage the production tubing  10   p  and the stuffing box  115  may be operated to engaged the sealed portion  150 . The ESP  105  may then be operated to pump production fluid  35  from the wellbore  5  to the tree  50  and through the tree to the surface separation, treatment, and storage equipment. 
     Advantageously, the sealed portion  150  obviates the need for grease injection while the ESP  105  is operating. Once the ESP  105  needs to be retrieved from the wellbore  5  for maintenance and/or replacement, the cable  130  may be inspected and reused to deploy the repaired/replaced ESP into the wellbore, the cable may be replaced and resealed, or the sealed portion may be cut and the remaining cable resealed to deploy the repaired/replaced ESP into the wellbore. 
     Alternatively, the cable  130  (with sealed portion  150 ) may be used to deploy and operate other downhole tools besides an ESP, such as a compressor. 
     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.