Patent Publication Number: US-9835001-B2

Title: Well instrumentation deployment past a downhole tool for in situ hydrocarbon recovery operations

Description:
REFERENCE TO RELATED APPLICATION 
     This application claims the priority of Canadian application No. 2,854,065, filed Jun. 9, 2014, the entire contents of which are incorporated herein by reference. 
     TECHNICAL FIELD 
     The technical field generally relates to in situ hydrocarbon recovery operations, such as Steam-Assisted Gravity Drainage (SAGD), and more particularly, to techniques involving downhole deployment of well instrumentation for enhanced in situ hydrocarbon recovery. 
     BACKGROUND 
     There are a number of in situ techniques for recovering hydrocarbons, such as heavy oil and bitumen, from subsurface reservoirs. Thermal in situ recovery techniques often involve the injection of a heating fluid, such as steam, in order to heat and thereby reduce the viscosity of the hydrocarbons to facilitate recovery. One technique, called Steam-Assisted Gravity Drainage (SAGD), has become a widespread process for recovering heavy oil and bitumen, particularly in the oil sands of northern Alberta. The SAGD process involves well pairs, each pair having two horizontal wells drilled in the reservoir and aligned in spaced relation one on top of the other. The upper horizontal well is a steam injection well and the lower horizontal well is a production well. 
     A SAGD operation typically begins in startup mode, in order to establish fluid communication between the injection well and the production well. After startup, the production well can be recompleted for mechanical lift. Mechanical lift can involve the installation of a downhole pump, such as an electric submersible pump (ESP), at the end of an associated production line to provide the hydraulic force for lifting production fluids to the surface via the associated production line. When a production well is completed with a downhole pump, instrumentation including, for example, optical fibers, thermocouples and/or pressure sensors, can be provided running from the surface downward along the pump production line and terminating at and clamped to the downhole pump. 
     The use of a downhole pump, such as an ESP, involves a number of challenges. For example, the installation of a downhole pump can limit or prevent the possibility of running instrumentation and/or carrying out logging or other operations below the pump into the producing interval of the well. In some scenarios, however, it can be desirable or necessary to monitor reservoir characteristics and/or process conditions below the pump to facilitate evaluation of different parameters (e.g., temperatures, pressures, flow rates, etc.) along the horizontal portion of the well and, in turn, manage well operations based on the collected data. 
     Conventional methods of getting instrumentation past a downhole pump deployed in a wellbore can involve time-consuming, extensive, and costly wellbore, wellhead and flowline modifications, and represent considerable downtime with various associated inefficiencies. Accordingly, various challenges still exist in the area of techniques for downhole deployment of well instrumentation in thermal in situ hydrocarbon recovery operations. 
     SUMMARY 
     In some implementations, there is provided a production assembly for in situ hydrocarbon recovery operations along a production well, including:
         a downhole pump deployed into the production well;   a guide string deployed into the production well ahead of the downhole pump;   at least one instrumentation line deployed into the production well inside the guide string; and   a transition device serially connected between the downhole pump and the guide string, including:
           a housing having a proximal end connected to the downhole pump and a distal end connected to the guide string;   a crossover channel extending through the housing and providing a crossover path for the at least one instrumentation line between an exterior of the transition device at the proximal end and an interior of the guide string at the distal end;   a sealing assembly including a plurality of high-temperature-resistant packing elements sized and shaped to seal the crossover channel around the at least one instrumentation line; and   a fluid channel extending through the housing radially offset from the crossover channel, wherein the fluid channel is sealed during a production mode and fluidly connected to the crossover channel during a deployment mode in order to supply a pressurized fluid into the crossover channel so as to propel the at least one instrumentation line forward inside the guide string.   
               

     In some implementations, the transition device includes a quick connect coupling provided at the proximal end of the housing for connection to the downhole pump. 
     In some implementations, the housing includes, from the proximal end to the distal end thereof:
         a canister portion housing parallel tubular sections defining the crossover channel and the fluid channel, and a Y-branch body having a crossover channel input, a fluid channel input and a guide string output; and   a pup joint assembly providing a path for the at least one instrumentation line between the guide string output of the Y-branch body and the guide string.       

     In some implementations, the guide string includes:
         a perforated segment having a closed forward extremity; and   a plurality of string segments serially connected between the transition device and the perforated segment.       

     In some implementations, the at least one instrumentation line includes a pump down plug at a forward end thereof sized and shaped to propel, during the deployment mode, the at least one instrumentation line forward within the guide string under action of the pressurized fluid. 
     In some implementations, there is provided a production assembly for hydrocarbon recovery operations along a production well, including:
         a downhole pump deployed into the production well;   a guide string deployed into the production well ahead of the downhole pump;   at least one instrumentation line deployed into the production well inside the guide string; and   a transition device serially connected between the downhole pump and the guide string, including a housing and a crossover channel extending through the housing and having a proximal end and a distal end, the crossover channel providing a crossover path for the at least one instrumentation line between an exterior of the transition device at the proximal end and an interior of the guide string at the distal end.       

     In some implementations, there is provided an assembly for use in hydrocarbon recovery operations along a well, including:
         a downhole tool deployed into the well;   a guide string deployed into the well ahead of the downhole tool;   at least one instrumentation line deployed into the well inside the guide string; and   a transition device serially connected between the downhole tool and the guide string, including a housing and a crossover channel extending through the housing and having a proximal end and a distal end, the crossover channel providing a crossover path for the at least one instrumentation line between an exterior of the transition device at the proximal end and an interior of the guide string at the distal end.       

     In some implementations, the assembly further includes a sealing assembly configured to seal the crossover channel around the at least one instrumentation line. 
     In some implementations, the sealing assembly includes a plurality of high-temperature-resistance packing elements. 
     In some implementations, the sealing assembly includes:
         a pack-off sleeve:   a pair of packing elements in contact with opposed ends of the pack-off sleeve;   a pair of pack-off rings each of which sandwiching a corresponding one of the pair of packing elements against the pack-off sleeve;   a pack-off body housing the pack-off sleeve, the pair of packing elements and the pair of pack-off rings, the pack-off body having a having a distal end connected to the proximal end of the crossover channel and a proximal end; and   a pack-off nut connected to the proximal end of the pack-off body, the pack-off nut compressing and retaining in fixed position the pack-off sleeve, the pair of packing elements and the pair of pack-off rings.       

     In some implementations, the pack-off sleeve, the pair of pack-off rings, the pack-off body and the pack-off nut are each made of a metallic material, and wherein the pair of packing elements are made of a compressible material. 
     In some implementations, the compressible material is a rubber material, a polymer material, an elastomer material or a thermoplastic material. 
     In some implementations, there is provided the sealing assembly further includes a thrust bearing positioned between the pack-off nut and a proximal one of the pair of pack-off rings, the thrust bearing being configured to provide sufficient compression force to the pair of packing elements to maintain a seal around the at least one instrumentation line while deploying the at least one instrumentation line inside the guide string. 
     In some implementations, the assembly further includes a fluid channel extending through the housing radially offset from the crossover channel, wherein the fluid channel is sealed during a production mode and fluidly connected to the crossover channel during a deployment mode in order to supply a pressurized fluid into the crossover channel so as to propel the at least one instrumentation line forward inside the guide string. 
     In some implementations, the at least one instrumentation line includes a plug at a forward end thereof sized and shaped to propel, during the deployment mode, the at least one instrumentation line forward within the guide string under action of the pressurized fluid. 
     In some implementations, the transition device includes a quick connect coupling provided at a proximal end thereof for connection to the downhole tool. 
     In some implementations, the quick connect coupling includes a lower member defining the proximal end of the transition device and an upper member connected to the downhole tool, the lower member and the upper member configured for mating engagement so as to enable control over a relative orientation of the transition device and the downhole tool upon connection therebetween. 
     In some implementations, the quick connect coupling further includes a retaining member preventing relative axial movement and disconnection of the lower and upper members. 
     In some implementations, the transition device includes:
         a canister portion housing parallel tubular sections defining the crossover channel and the fluid channel, and a Y-branch body having a crossover channel input, a fluid channel input and a guide string output; and   a pup joint assembly providing a path for the at least one instrumentation line between the guide string output of the Y-branch body and the guide string.       

     In some implementations, the guide string includes:
         a perforated segment having a closed forward extremity; and   a plurality of string segments serially connected between the transition device and the perforated segment.       

     In some implementations, the downhole tool, the guide string and the transition device are provided in a substantially coaxial arrangement with respect to one another. 
     In some implementations, the downhole tool is an electrical submersible pump (ESP). 
     In some implementations, the downhole tool is located at or near a heel of the well. 
     In some implementations, the guide string extends to a toe of the well. 
     In some implementations, the at least one instrumentation line is configured to remain in place upon removal of the downhole tool from the well for maintenance, inspection or replacement. 
     In some implementations, the at least one instrumentation line is clamped onto an exterior of the downhole tool. 
     In some implementations, the at least one instrumentation line includes one or more of an optical fiber, a thermocouple, a bubble tube, a pressure sensor and an acoustic sensor. 
     In some implementations, the at least one instrumentation line includes a plurality of fiber-optic temperature sensors. 
     In some implementations, each of the at least one instrumentation line includes a capillary tube and distributed sensing elements inserted in the capillary tube. 
     In some implementations, there is provided a transition device for use with a downhole pump employed for hydrocarbon recovery operations along a production well and with a guide string insertable into the production well ahead of the downhole pump, including:
         a housing serially connectable between the downhole pump and the guide string;   a sealable crossover channel extending through the housing and having a proximal end and a distal end, the crossover channel providing a crossover path for at least one instrumentation line between an exterior of the transition device at the proximal end and an interior of the guide string at the distal end; and   a fluid channel extending through the housing radially offset from and capable of establishing fluid communication with the crossover channel, the fluid channel being configured to provide a pressurized fluid into the crossover channel in order to propel the at least one instrumentation line forward inside the guide string.       

     In some implementations, there is provided a transition device for use with a downhole pump employed for in situ hydrocarbon recovery operations along a production well and with a guide string insertable into the production well ahead of the downhole pump, including:
         a housing having a proximal end connectable to the downhole pump and a distal end connectable to the guide string;   a quick connect coupling provided at the proximal end of the housing for connection to the downhole pump;   a crossover channel extending through the housing and providing a crossover path for at least one instrumentation line between an exterior of the transition device at the proximal end and an interior of the guide string at the distal end;   a sealing assembly including a plurality of high-temperature-resistant packing elements sized and shaped to seal the crossover channel around the at least one instrumentation line; and a fluid channel extending through the housing radially offset from and in fluid communication with the crossover channel, configured to provide a pressurized fluid into the crossover channel in order to propel the at least one instrumentation line forward inside the guide string.       

     In some implementations, the quick connect coupling includes a lower member defining the proximal end of the housing and an upper member connectable to the downhole pump, the lower member and the upper member being configured for mating engagement so as to enable control over a relative orientation of the transition device and the downhole pump upon connection therebetween. 
     In some implementations, the quick connect coupling further includes a retaining member preventing relative axial movement and disconnection of the lower and upper members. 
     In some implementations, the transition device further includes, from the proximal end to the distal end of the housing:
         a canister portion housing parallel tubular sections defining the crossover channel and the fluid channel, and a Y-branch body having a crossover channel input, a fluid channel input and a guide string output; and   a pup joint assembly providing a path for the at least one instrumentation line between the guide string output of the Y-branch body and the guide string.       

     A transition device for use with a downhole tool employed in hydrocarbon recovery operations along a production well and with a guide string insertable into the production well ahead of the downhole tool, including:
         a housing serially connectable between the downhole tool and the guide string;   a sealable crossover channel extending through the housing and having a proximal end and a distal end, the crossover channel providing a crossover path for at least one instrumentation line between an exterior of the transition device at the proximal end and an interior of the guide string at the distal end; and   a fluid channel extending through the housing radially offset from and capable of establishing fluid communication with the crossover channel, the fluid channel being configured to provide a pressurized fluid into the crossover channel in order to propel the at least one instrumentation line forward inside the guide string       

     In some implementations, the transition device further includes a sealing assembly configured to seal the crossover channel around the at least one instrumentation line. 
     In some implementations, the sealing assembly includes a plurality of high-temperature-resistance packing elements. 
     In some implementations, the sealing assembly includes:
         a pack-off sleeve:   a pair of packing elements in contact with opposed ends of the pack-off sleeve;   a pair of pack-off rings each of which sandwiching a corresponding one of the pair of packing elements against the pack-off sleeve;   a pack-off body housing the pack-off sleeve, the pair of packing elements and the pair of pack-off rings, the pack-off body having a having a distal end connected to the proximal end of the crossover channel and a proximal end; and   a pack-off nut connected to the proximal end of the pack-off body, the pack-off nut compressing and retaining in fixed position the pack-off sleeve, the pair of packing elements and the pair of pack-off rings.       

     In some implementations, the pack-off sleeve, the pair of pack-off rings, the pack-off body and the pack-off nut are each made of a metallic material, and wherein the pair of packing elements are made of a compressible material. 
     In some implementations, the compressible material is a rubber material, a polymer material, an elastomer material or a thermoplastic material. 
     In some implementations, the sealing assembly further includes a thrust bearing positioned between the pack-off nut and a proximal one of the pair of pack-off rings, the thrust bearing being configured to provide sufficient compression force to the pair of packing elements to maintain a seal around the at least one instrumentation line while deploying the at least one instrumentation line inside the guide string. 
     In some implementations, the transition device further include a quick connect coupling provided at a proximal end thereof for connection to the downhole tool. 
     In some implementations, the quick connect coupling includes a lower member defining the proximal end of the transition device and an upper member connectable to the downhole tool, the lower member and the upper member being configured for mating engagement so as to enable control over a relative orientation of the transition device and the downhole tool upon connection therebetween. 
     In some implementations, the quick connect coupling further includes a retaining member preventing relative axial movement and disconnection of the lower and upper members. 
     In some implementations, the transition device further includes:
         a canister portion housing parallel tubular sections defining the crossover channel and the fluid channel, and a Y-branch body having a crossover channel input, a fluid channel input and a guide string output; and   a pup joint assembly providing a path for the at least one instrumentation line between the guide string output of the Y-branch body and the guide string.       

    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a side cross-sectional view schematic of a SAGD well pair. 
         FIG. 2  is a front cross-sectional view schematic of a SAGD well pair, an infill well and a step-out well. 
         FIG. 3  is a side cross-sectional view schematic of a production well including a downhole pump, a guide string, instrumentation deployed in the guide string, and a transition device between the pump and the guide string, in a production mode. 
         FIG. 4  is a perspective view schematic of a transition device connected to a guide string. 
         FIG. 5  is a side cross-sectional view schematic of a transition device connected to a guide string. 
         FIG. 6  is a side cross-sectional view schematic of part of a transition device. 
         FIG. 7  is a side cross-sectional view schematic of a production assembly. 
         FIG. 8  is a process flow diagram of a completion method for deploying an implementation of a production assembly. 
         FIGS. 9A to 9H  illustrate steps of a completion method for deploying an implementation of a production assembly. 
         FIG. 10  is a side cross-sectional view schematic of part of a transition device with a canister portion and a sealing assembly removed. 
         FIG. 11  is a side cross-sectional view schematic of a sealing assembly of a transition device. 
         FIG. 12  is a side cross-sectional view schematic of part of a transition device with a canister portion removed. 
         FIG. 13  is a perspective view schematic of a guide string connected to a transition device. 
         FIG. 14  is a side cross-sectional view schematic of instrumentation lines being pumped down a guide string. 
         FIGS. 15A and 15B  are respectively a perspective view schematic and a side cross-sectional view schematic of a quick connect coupling. 
         FIG. 16  is a process flow diagram of a method for upkeeping a downhole pump. 
         FIGS. 17A to 17D  illustrate steps of a method for upkeeping a downhole pump. 
     
    
    
     DETAILED DESCRIPTION 
     Various techniques are described for deploying instrumentation lines past a downhole tool received in a well of a hydrocarbon recovery operation. In some implementations, a transition device is serially connected between a downhole pump and a guide string extending in the horizontal portion of a production well, and is provided with two laterally offset and independently sealable channels. One channel is a crossover channel along which instrumentation lines transition from being outside of the transition device to being inside of the guide string. The other channel is a fluid channel through which pressurized fluid can be delivered into the crossover channel in order to propel the instrumentation lines down the guide string. 
     In some implementations, once instrumentation lines have been pumped down into the guide string, the fluid channel is sealed and the pump, transition device, instrumentation lines, and guide string are together deployed downhole as a single production assembly, in which the pump and instrumentation lines can be independently replaced or maintained. For example, in the event the pump has to be pulled for inspection, maintenance or replacement, the instrumentation lines can be sealed or packed off in the crossover channel to ensure containment of the wellbore production fluids within the well. 
     An existing method of getting instrumentation below a downhole pump involves deploying the instrumentation in a separate guide string running adjacent the pump production line. However, such a method typically entails extensive and time-consuming wellhead modifications, limits the annular space in the wellbore, and makes achieving proper positioning of the downhole instrumentation difficult. Also, the presence of an adjacent guide string can contribute to reducing the run-life of the pump. Other existing methods can also result in significant wellhead, wellbore and/or flowline modifications, which can lead to a number of disadvantages, such as an excessively high wellhead that is inefficient to operate and involves compromises in safety, and delayed production with the associated economic downside. 
     In contrast to existing methods, in some implementations, the techniques described herein enable instrumentation lines to be deployed below a downhole pump and along the producing interval of the well with no or minimal downhole and/or surface modifications, thus avoiding down time and reducing associated recompletion costs. In addition, by sealing or packing off the crossover channel of the transition device, the instrumentation can be decoupled from the downhole pump, allowing the pump to be pulled and replaced without having to pull the instrumentation out of the guide string. This can be advantageous when considering that downhole pumps typically require inspection, maintenance or replacement before the instrumentation, and that pulling the instrumentation out of the guide string with unnecessary frequency can subject the instrumentation to risk of damage, which is best reduced or avoided. 
     Furthermore, in some implementations, by providing the transition device in a serial arrangement with the pump and the guide string, obstruction of the annular space around the pump can be reduced or avoided. A number of advantages can be achieved with this arrangement including one or more of the following:
         Instrumentation bypassing a downhole pump and deployed to the toe of a production well independently of the position of the pump within the wellbore;   Production from the toe of a production well; and/or   Steam injection to the toe of a production well. More regarding the various operational and structural features of the techniques will be described in greater detail below.       

     It should be noted that the transition device according to the techniques described herein is not limited for use with a downhole pump, but can be applicable to deploy instrumentation below other types of downhole tools and equipment where it is desirable or necessary that instrumentation be passed through or around the downhole tool or equipment to enter a guide string deployed below the downhole tool or equipment. In some implementations, the instrumentation can also be clamped externally to a piping, string or tubing above the downhole tool or equipment. The various techniques described herein can be applicable to production, injection and observation wells. In addition, in some implementations, the transition device could be applicable to deploy not only instrumentation lines, but also other equipment such as, for example, chemical injection lines to the toe of horizontal wellbores. 
     Throughout the present specification, the terms “above”, “upper”, “upward”, “upstream” and similar terms refer to a direction closer to the head of a wellbore, while the terms “ahead”, “below”, “forward”, “downward”, “lower”, “downstream” and similar terms refer to a direction closer to the bottom of the wellbore. Additionally, the term “proximal” refers to a location, an element, or a portion of an element that is further above with respect to another location, element, or portion of the element, while the term “distal” refers to a location, an element, or a portion of an element, that is further below another location, element, or portion of the element. 
     Production Well Implementations 
     The various techniques described herein can be implemented in various types of production wells that require or could benefit from having instrumentation or other well equipment deployed below a downhole pump with no or minimal surface and/or downhole modifications. For example, in some implementations, the production well can be part of a SAGD well pair including an overlying SAGD injection well, or can be operated as another production well, such as an infill well or a step-out well, that is part of a SAGD operation. Alternatively, in some implementations, some techniques described herein can be used for Cyclic Steam Stimulation (CSS) wells or In Situ Combustion (ISC) wells. 
     Referring to  FIG. 1 , a SAGD operation  20  can include an injection well  22  overlying a production well  24  to form a well pair  26 . Each well includes a vertical or slanted section extending from the surface  28  into the hydrocarbon-containing reservoir  30 , and a generally horizontal section that extends within a pay zone of the hydrocarbon-containing reservoir  30 . The injection well  22  and the production well  24  are separated by an interwell region  32  that is typically immobile at initial reservoir conditions. During startup mode, the interwell region  32  is mobilized by introducing heat, typically conveyed by a mobilizing fluid such as steam, into one or more of the wells. 
     In some implementations, steam is injected into the injection well  22  and the production well  24  to heat the interwell region  32  and mobilize the hydrocarbons to establish fluid communication between the two wells. Other mobilizing fluids, such as organic solvents, can also be used to mobilize the reservoir hydrocarbons by heat and/or dissolution mechanisms. The well pair  26  also has a heel  34  and a toe  36 , and it is often desired to circulate the mobilizing fluid along the entire length of the wells. Once the well pair  26  has fluid communication between the two wells, the well pair  26  can be converted to normal operation where steam is injected into the injection well  22  while the production well  24  is operated in production mode to supply hydrocarbons to the surface  28 . 
     Turning briefly to  FIG. 2 , SAGD well pairs  26  can be arranged in generally parallel relation to each other to form an array of well pairs  26 . As the SAGD operation  20  progresses, steam chambers  38  form and grow above respective injection wells  22 . Infill wells  40  can be drilled, completed and operated in between SAGD well pairs, and step-out wells  42  can be drilled, completed and operated adjacent to one SAGD well pair. In some scenarios, such infill and start-up wells can benefit from the various techniques described herein. In particular, since temperature variations along infill wells and step-out wells are often more pronounced than along well pair production wells, providing distributed temperature sensing instrumentation along the horizontal portion of infill wells and step-out wells can provide information as to well conformance as the well is produced to determine the progress of full chamber development along the well. Furthermore, in some implementations, as infill wells and step-out wells do not have corresponding injector wells, instrumentation has to be deployed inside the infill wells and step-out wells themselves. 
     Production Well Completion 
     Referring to  FIG. 3 , the production well  24  includes a transition device  44 , which is serially connected between a downhole pump  46  and a guide string  48  and also enables the deployment of instrumentation  50  within the guide string  48 , past the pump  46  and into the horizontal portion of the well  25 . More regarding the construction and operation of the transition device  44  will be discussed further below. 
     Referring still to  FIG. 3 , in some implementations the production well  24  is completed with tubing and/or liner structures. The production well completion can also include devices for flow control, isolation, artificial lifting and pumping, instrumentation deployment, gravel packing and/or various other completion structures for ensuring functionality and stability of the production well  24 . The completion design can allow for the deployment and operation of the instrumentation  50  below the downhole pump  46 , in accordance with the various techniques described herein. It should be noted that the production well  24  can assume different constructions and configurations, depending on the particularities of the hydrocarbon recovery process in which the well is employed and the components used to complete the well. 
     In some implementations, the production well  24  includes a surface casing  52  provided at an inlet of the wellbore proximate the surface, and an intermediate casing  54  provided within the wellbore and extending from the surface downward into the reservoir in the vertical or slanted section of the wellbore, in the curved intermediate section of the wellbore, and in part of the horizontal section of the wellbore at the heel  34 . The production well  24  can also include a liner  56  provided in the horizontal portion of the wellbore. The liner  56  can be installed by connection to a distal part of the intermediate casing  54  via a liner packer  58 . The liner  56  can have various constructions including various slot patterns, blank sections, and other features designed for the given application and reservoir characteristics. 
     In some implementations, the production well  24  can also include a tailpipe  60  sized for insertion into the liner  56  and defining an annulus  62  between an inner surface of the liner  56  and an outer surface of the tailpipe  60 . The tailpipe  60  can extend from a location proximate to and above the liner packer  58  to the toe  36  of the production well  24 , where the tailpipe  60  has a distal opening  64  through which fluids can flow. The tailpipe  60  can be installed to a proximal part of the liner  56  via a tailpipe packer  66 . The tailpipe packer  66  can seal the proximal end of the tailpipe  60  and thus force hydrocarbon-containing fluids flowing through slots in the walls of the liner  56  and into the annulus  62  to enter the tailpipe  60  through the distal opening  64  of the tailpipe  60 . 
     In some implementations, the pump  46  can be attached at the end of an associated production line  68  and received inside the intermediate casing  54  in order to provide a hydraulic force for enabling displacement of production fluids  70  toward the surface. The pump  46  can be an electrical submersible pump (ESP) or another artificial lift device, and be located at various different locations within the well  24 . For example, the pump  46  can be located proximate and just upstream (e.g., a few meters) from the liner packer  58 . 
       FIG. 3  also illustrates fluid flow during production mode. Mobilized hydrocarbons flow through slots in the walls of the liner  56  and enter the annulus  62  defined between the tailpipe  60  and the liner  56 . In some scenarios, the production fluids  70  flow toward the toe  36  of the well  24  where the fluids  70  enter the distal opening  64  of the tailpipe  60  and then flow toward the heel  34  of the well  24  within the tailpipe  60 . Hydraulic force for enabling displacement of the production fluids  70  is provided by the pump  46 . The pump production line  68  includes a tubing through which production fluids  70  pumped by the pump  46  can be supplied to the surface where the production fluids  70  can be processed. 
     Referring still to  FIG. 3 , the instrumentation  50  can be provided extending along a length of the production well  24 . The instrumentation  50  can include one or more instrumentation lines and be provided with various devices for detecting or measuring characteristics of the reservoir and/or the process conditions. The instrumentation  50  can include optical fibers, thermocouples, bubble tubes, pressure sensors and/or acoustic sensors. For example, in some implementations, the instrumentation  50  can include a plurality of fiber-optic temperature sensors distributed along the horizontal section of the well  24  for monitoring the temperature of the production fluids  70 . The instrumentation  50  can be configured to measure and transmit data regarding various operational and/or reservoir characteristics, such as temperatures, pressures, seismic events, etc. before and/or during operation of the production well  24 . The operating conditions of the well  24  can be regulated based on the data collected via the instrumentation  50  deployed in the wellbore. 
     In some implementations, the instrumentation  50  extends from the surface downward along the outside of the pump production line  68  and is clamped onto the exterior of the pump  46 . The instrumentation  50  then reaches the transition device  44 , at which point the instrumentation  50  crosses over internally and is run down within the guide string  48 . The construction, operation, and deployment of the transition device  44  will now be described. 
     General Construction of Transition Device Implementations 
     Referring to  FIGS. 4 to 6 , the general construction of an implementation of the transition device  44  is illustrated. Broadly described, the transition device  44  can include a housing  72 , a crossover channel  74 , a fluid channel  76 , and a sealing assembly  78 . More regarding the components of the transition device  44  will be discussed further below. 
     Returning briefly to  FIG. 3 , the housing  72  has a proximal end  80  and a distal end  82  configured for connection to the downhole pump  46  and the guide string  48 , respectively. The housing  72  generally defines the overall size and shape of the transition device  44 , and includes, connects and/or supports the different components of the transition device  44 . In some implementations, obstruction of the flow area around the pump  46  can be reduced or avoided by providing the transition device  44  in a substantially coaxial arrangement with the pump  46  and the guide string  48 , and by ensuring that the largest outer diameter along the length of the transition device  44  does not exceed the largest outer diameter along the length of the pump  46 . The transition device  44  can include a quick connect coupling  84  provided at the proximal end  80  of the housing  72  for connection to the downhole pump  46 . More regarding the quick connect coupling  84  will be discussed further below. 
     Returning to  FIGS. 4 to 6 , in some implementations, the housing  72  includes, from the proximal end  80  to the distal end  82 , a canister portion  86  and a pup joint assembly  88 . The canister portion  86  can house parallel tubular sections defining the crossover channel  74  and the fluid channel  76 , so that the crossover channel  74  and the fluid channel  76  can constitute two independently sealable channels in the transition device  44 . The canister portion can also house a Y-branch body  90  having a crossover channel input  92  connected to the distal end of the crossover channel  74 , a fluid channel input  94  connected to the distal end of the fluid channel  76  and a guide string output  96  connected to the proximal end of the guide string  48 . The canister portion  86  can be provided to help reinforce the structure of the transition device  44  and protect the components housed by the canister portion  86  from damage when the transition device  44  is deployed downhole. The pup joint assembly  88  can provide a path  98  for the instrumentation lines  50  between the guide string output  96  of the Y-branch body  90  and the guide string  48 . More regarding the pup joint assembly  88  will be discussed further below. 
     Referring still to  FIGS. 4 to 6 , the crossover channel  74  extends through the housing  72  and provides a crossover path  100  along which the instrumentation lines  50  are fed in order to be pumped down the guide string  48 . In particular, by passing through the crossover channel  74 , the instrumentation lines  50  transition from being outside of the transition device  44  at the proximal end  80  to being inside of the guide string  48  at the distal end  82 . Furthermore, in some implementations, the crossover channel  75  is configured not only to receive and accommodate the instrumentation lines  50 , but also to be sealed against the flow of fluids, for example, during well production, instrumentation deployment and/or pump removal operations. In order to prevent the flow of fluids across the crossover channel  74 , the transition device  44  can include a sealing assembly  78  provided with a packing structure constructed and arranged to seal the crossover channel  74  around the instrumentation lines  50 . More regarding the sealing assembly  78  will be discussed further below. 
     Referring still to  FIGS. 4 to 6 , in some implementations, the fluid channel  76  extends through the housing  72  parallel to but radially offset from the crossover channel  74 . In some implementations, the fluid channel  76  is configured to be sealed during well production and pump removal, but to remain open during instrumentation deployment. In particular, the fluid channel  76  can provide a sealable pathway for delivering, during instrumentation deployment, a pressurized fluid from the surface to the crossover channel  74  in order to propel the instrumentation lines  50  forward inside the guide string  48  and near the toe of the well (not shown in  FIGS. 4 to 6 ). Accordingly, in some implementations, once the instrumentation lines  50  have been pumped down into the guide string  48  by the pressurized fluid supplied to the crossover channel  74  via the fluid channel  76 , the fluid channel  76  can be sealed and the pump  46 , transition device  44 , instrumentation lines  50 , and guide string  48  can be together deployed downhole as a single production assembly, as will now be discussed. 
     Deployment and Production Assembly Implementations 
     Referring to  FIG. 7 , a production assembly  102  includes the transition device  44 , the pump  46 , the guide string  48 , the instrumentation lines  50  and the pump production line  68 . Various completion deployment strategies may be undertaken in order to deploy and install a production assembly  102  within a production well. In some implementations, the production assembly can be provided as a pre-assembled apparatus for deployment as a unit into the well. Alternatively, a production assembly kit can be provided for partial or complete assembly prior to deployment. In some implementations, the production assembly  102  is provided with pre-determined dimensions based on other well components and/or on various other factors, such as temperature conditions, pressure conditions, flow rates, friction factors and pressure drops of various fluids to be flowed through the well. In addition, the dimensions can be pre-determined based on well designs that contemplated deploying a production assembly  102  for a hydrocarbon recovery process, or for well designs that did not initially contemplate such a process. 
     With additional reference to  FIG. 8 , a completion method for deploying an implementation of the production assembly can include several steps that will be explained in further detail below. It is to be noted that in some implementations some of the steps could be performed in a different order than described herein. 
     Deployment of the Guide String ( 200 ) 
     The initial step involves deploying the guide string  48  into the production well  24  by itself, that is, without the other components of the production assembly attached to the guide string  48 , as shown in  FIG. 9A . 
     This step, which can be referred to as a “dummy run”, can be performed to verify that the guide string  48  can advance to a sufficient or desired depth into the wellbore, for example to or near the toe  36  of the well  24 , under its own weight without buckling or otherwise deforming. Because the guide string  48  typically weighs much less than both the pump and transition device, making this dummy run to assess the depth at which the guide string  48  can descend under its own weight can reduce the risk that excessive compression forces are exerted on the guide string  48  when the production assembly is actually deployed into the wellbore. Once the guide string  48  has landed to a sufficient or desired depth into the well  24 , the dummy run can involve partially retracting the guide string  48  to the surface  28  until the portion of the guide string  48  that remains in the well  24  corresponds to the intended length of the guide string  48  in the production assembly, as illustrated in  FIG. 9B . Then, the dummy run can include removing the extraneous portion of the guide string  48  that has been pulled back to the surface  28 , as illustrated in  FIG. 9C . 
     For example, in one scenario, the length of the wellbore from surface to the toe of the well can be 1500 meters and the pump can be landed at a depth of 500 meters into the wellbore, so that the intended length of the guide string in the production assembly is 1000 meters. In such a case, the dummy run would involve a first step of deploying 1500 meters of guide string into the well, followed by a step of pulling back and removing from the well the extraneous 500 meters of guide string corresponding to the pump landing depth, so that only 1000 meters of guide string remain in the well. 
     The guide string can be provided as any type of tubing string, such as a jointed pipe or coiled tubing, capable of receiving and accommodating the instrumentation lines. The particular size of the guide string can depend on the requirements of the given application. For example, in some implementations, the outer diameter of the guide string can be between about 33 millimeters and about 50 millimeters. It is to be noted that this range is provided for illustrative purposes and the techniques described herein can be operated outside this range. In addition, in some implementations, it is desirable that the diameter and weight of the guide string be kept as small as possible to both maximize the wellbore flow area and minimize the friction drag acting on the guide sting that could lead to excessive compression forces on the downhole pump, while remaining sufficiently large and heavy to house the instrumentation lines and exhibit adequate mechanical strength. 
     In some implementations, a preliminary cleanout step can be performed prior to the dummy run in order to remove sand and other solid particles from the wellbore. In one scenario, the cleanout process can involve: inserting a cleanout tubing string into the tailpipe, generally down to the toe of the well; pumping a cleanout fluid down into the well; entraining the solid particles into the wash fluid; and carrying the solid particles to the surface. Depending on the given application, the preliminary cleanout process can be implemented using a “direct circulation” technique, in which the cleanout fluid is pumped down the cleanout tubing string and the return fluid travels up inside the annulus defined between the cleanout tubing string and the tailpipe, or a “reverse-circulation” technique, in which the cleanout fluid is pumped down the annulus and the return fluid travels up through the cleanout tubing string. Alternatively, the cleanout fluid can be pumped ahead of the cleanout tubing string and into the formation where circulation is not attainable. Injecting cleanout fluid without using tubing string could also be envisioned in some scenarios. 
     Connection of the Transition Device to the Guide String ( 202 ) 
     Referring to  FIG. 9D , once the distal end of the guide string  48  has been lowered to the intended depth within the wellbore, at the surface  28 , the proximal end of the guide string  48  can be connected to the distal end  82  of the transition device  44 . In some implementations, the transition device  44  can be provided as a pre-assembled apparatus ready for connection to the proximal end of the guide string  48 . Alternatively, the transition device  44  can be provided as a kit of components for partial or complete assembly prior to connection with the guide string  48 . 
     For example, referring back to  FIGS. 4 to 6 , in one scenario, connecting the transition device  44  to the guide string  48  can involve one or more of the following operations:
         Connection of the distal end of the pup joint assembly  88  to the proximal end of the guide string  48 ;   Connection of the guide string output  96  of the Y-branch body  90  to the proximal end of the pup joint assembly  88 ;   Connection of the distal end of the crossover channel  74  to the crossover channel input  92  of the Y-branch body  90 ; and/or   Connection of the distal end of the fluid channel  76  to the fluid channel input  94  of the Y-branch body  90 .       

     Referring still to  FIGS. 4 to 6 , in one implementation, the pup joint assembly  88  can include a lower pup joint  104  connected to the guide string  48  and an upper pup joint  106  connected to the guide string output  96  of the Y-branch body  90 . The lower pup joint  104  can be sized and configured to stabilize and strengthen the connection between the transition device  44  and the guide string  48 . For example, in one implementation, the lower pup joint  104  has a length of about 0.6 meter and an outer diameter of about 60 millimeters. 
     The upper pup joint  106  can be sized and configured to provide a surface against which the packing unit of a blowout preventer can be press-fitted to seal the annulus between the outer surface of the upper pup joint  106  and the inner surface of the wellbore and thus confine well fluids to the wellbore when the pump is pulled to the surface for inspection, maintenance or replacement, as discussed further below. The outer diameter of the upper pup joint  106  can be selected to lie within the range of pipe diameters which can effectively be sealed by the blowout preventer. For example, in one implementation, the upper pup joint  106  has a length of about 3 meters and an outer diameter of about 90 millimeters. It is to be noted that these values for the dimensions of the lower and upper pup joints are provided for illustrative purpose and the techniques described herein can be operated beyond these values. 
     Insertion of the Instrumentation Lines Through the Crossover Channel ( 204 ) 
     Referring to  FIGS. 9E and 10 , the distal end of the instrumentation lines  50  are then inserted through the crossover channel  74  of the transition device  44 . At this step, the sealing assembly and the canister portion are not yet installed on the transition device  44 . The instrumentation lines  50  can be provided as stainless steel capillary tubes in which distributed sensing elements (e.g., fiber-optic-based distributed sensors) are inserted for monitoring reservoir characteristics and/or process conditions along the wellbore. 
     Sealing of the Crossover Channel ( 206 ) 
     Referring to  FIG. 11 , once the instrumentation lines  50  have been inserted through the crossover channel  74 , the crossover channel  74  can be sealed by installing the sealing assembly  78  around the instrumentation lines. Depending on the given application, the sealing assembly  78  can have various constructions and configurations. In particular, the sealing assembly  78  can include a plurality of components cooperating to seal the crossover channel  74  by preventing fluid flow along the instrumentation lines  50 . 
     For example, in the implementation of  FIG. 11 , the sealing assembly  78  includes a central pack-off sleeve  108 , a pair of packing elements  110  positioned in contact with each end of the central pack-off sleeve  108 , and a pair of pack-off rings  112  each of which sandwiching a corresponding packing element  110  against one end of the central pack-off sleeve  108 . The pack-off sleeve  108 , packing elements  110  and pack-off rings  112  can be mounted around the instrumentation lines  50  and be provided with axial bores through which the instrumentation lines  50  can be received. In some implementations, the pack-off sleeve  108 , packing elements  110  and pack-off rings  112  can be housed in a pack-off body  114  having a distal end connected to the proximal end of the crossover channel  74  and a proximal end to which a pack-off nut  116  can be threadedly connected. When tightened, the pack-off nut  116  compresses and retains in a fixed position the pack-off sleeve  108 , packing elements  110  and pack-off rings  112 , thereby increasing the sealing force. 
     In some implementations, the pack-off sleeve  108 , packing elements  110 , pack-off rings  112  and pack-off nut  116  are all split components. As a result, these components can all be mounted around and pulled apart from the instrumentation lines  50  in a radial direction, that is, without having to be slid off of the proximal end of the instrumentation lines  50 , thereby facilitating assembly and disassembly of the sealing assembly  78 . In this regard, it is to be noted that the number, shape, and method of mounting the sealing components included in the sealing assembly  78  can be varied while still providing a hermetic seal along the crossover channel  74 . 
     Referring still to  FIG. 11 , the pack-off sleeve  108 , rings  112 , body  114  and nut  116  can be made of a metallic material, such as stainless steel. The packing elements  110 , which are the components of the sealing assembly  78  that create the seal around the outer surface of the instrumentation lines  50  can be made from a compressible material, such as a rubber, polymer, elastomer and/or thermoplastic material. Examples of such materials include elastomers such as nitrile rubber (NRB) and hydrogenated nitrile rubber (HNBR), and thermoplastic materials such as Polytetrafluoroethylene (PTFE). The type of material that is used for the packing elements will depend on various factors, such as the downhole operating temperatures, and the exposure to produced or injected fluids and gases. For example, in some implementations, nitrile-based rubber can be used when the transition device is located at surface, as nitrile is more flexible and can achieve a superior seal while pumping the instrumentation lines down the guide string, and be replaced by PTFE when the transition device is deployed downhole, as PTFE can better withstand elevated downhole temperature conditions. In particular, in implementations involving CSS or ISC wells, graphoil or high-temperature-resistant elastomers can be used for the packing elements to withstand the higher temperature often found in these types of wells. 
     Pumping of the Instrumentation Lines Down the Guide String ( 208 ) 
     Referring to  FIGS. 9F and 12 , once the crossover channel  74  has been sealed by the sealing assembly  78 , the instrumentation lines  50  can be pumped down the guide string  48 . This step can involve providing, via the fluid channel  76 , a pressurized fluid  118 , such as pressurized water, into the crossover channel  74  in order to propel the instrumentation lines  50  forward inside the guide string  48 . The pressurized fluid  118  can be supplied by a deployment pump  120  located at the surface, such as a rig pump or pump truck, and fluidly connected to the fluid channel  76  via a pump line  122  connected at the proximal end  80  of the transition device  44 . The pressurized fluid  118  is pumped into the guide string  48  until the required length of the instrumentation lines  50  has been deployed into the guide string  48 . Returning briefly to  FIG. 11 , in some implementations, it can be desirable or necessary to ensure that the seal provided by the sealing assembly  78  remains effective throughout the pumping operation, which can involve continuously or intermittently monitoring the tightening of the pack-off nut  116  on the pack-off body  114 . 
     Referring to  FIG. 13 , in some implementations, the guide string  48  can include a perforated segment  124  having a closed forward extremity  126 , which can be referred to as a “bull nose”, and a plurality of non-perforated segments  128  serially connected between the distal end  82  of the transition device  44  and the perforated segment  124  (only two of such non-perforated segments  128  are shown in  FIG. 13 ). The peripheral perforations at the distal end of the guide string  48  provide release paths for the pressurized fluid that is used for pumping the instrumentation lines down the guide string  48 , while the bull nose  126  provides an abutting surface that prevents the instrumentation lines from being pushed too far and beyond the guide string  48  under the action of the pressurized fluid. 
     Referring briefly to  FIG. 14 , in some implementations, a pump down plug or pig  130  is connected to the distal end of the instrumentation lines  50 . The pump down plug  130  is sized and shaped to pull the instrumentations forward within the guide string  48  under the propelling force exerted by the pressurized fluid  118 , thereby facilitating the instrumentation deployment. In addition, in scenarios where a pair of instrumentation lines  50  is provided to achieve dual-ended fiber-optic-based distributed sensing, a turnaround sub or U-tube  132  can be provided that connects the distal ends of the two instrumentation lines  50  and that allows a same fiber optic sensing cable(s) to be deployed inside one or both instrumentation lines  50  after the installation of the instrumentation lines  50  and downhole pump is complete. 
     Turning back to  FIG. 11 , in some implementations, the sealing assembly  78  includes a thrust bearing  134  positioned between the pack-off nut  116  and one of the pack-off rings  112 . The thrust bearing  134  can ensure or contribute to ensuring that the seal around the instrumentation lines  50  remains hermetic while the instrument lines  50  are pumped down the guide string  48 . For example, the thrust bearing  134  can ensure that tightening the pack-off nut  116  can communicate sufficient compression force to the packing elements  110  to provide a hermetic seal while running the instrumentation lines  50  through the sealing assembly  78 . The thrust bearing  134  can also reduce or prevent unwanted rotation of the packing elements  110  and/or instrumentation lines  50 , which would otherwise increase friction and prevent or impede the deployment of the instrumentation lines  50  into the guide string  48 . 
     Referring to  FIGS. 4 to 6 , a number of additional steps can be performed after deploying the instrumentation lines down the guide string, including one or more of the following:
         Replacement of the packing elements  110  with high-temperature-resistant packing elements  110  capable of withstanding downhole temperature conditions in preparation of deploying the production assembly in wellbore;   Assessment of the integrity of the seal around the instrumentation lines  50  via a pressure-test port  136  provided on the pack-off body  114 ;   Disconnection of the deployment pump and sealing of the fluid channel  74 , for example using a valve threaded to the proximal end  80  of the transition device  44 ; and/or   Installation of the casing portion  86  of the transition device  44  to protect the internal parts of the transition device  44  from damage for when the transition device  44  is deployed downhole.
 
Connection of the Downhole Pump to the Transition Device ( 210 )
       

     Referring to  FIGS. 9G, 15A and 15B , once the instrumentation lines  50  have been deployed, the proximal end  80  of the transition device  44  can be disconnected from the deployment pump and be connected to the downhole pump  46 . In some implementations, the connection between the downhole pump  46  and the transition device  44  can be established by means of a quick connect coupling  84 . The quick connect coupling  84  can include a lower member  138 , which corresponds to the tubular section defining the fluid channel and whose end coincides with the proximal end  80  of the transition device  44 , and an upper member  140  connectable to the bottom section of the downhole pump  46 . 
     The lower member  138  and the upper member  140  can include complementary sets of interlocking teeth  142  configured for mating engagement, so as to enable control over the relative orientation between the transition device  44  and the downhole pump  46  upon connection. Such a control can be advantageous in implementations where it is desirable or required that the instrumentation lines  50  exiting the transition device  44  and the pump cable already provided on the downhole pump  46  be clamped onto different sides of the downhole pump  46 . 
     The quick connect coupling  84  can also include a retaining member  144 , which can be slid over the mated interlocking teeth  142  to form a joint which prevents relative movement and disconnection of the interlocked lower and upper members  138  and  140  in the axial direction. In some implementations, the quick connect coupling  84  can also seal the fluid channel of transition device  44  upon connecting the transition device  44  and downhole pump  46 . Alternatively, other means could be employed to seal the fluid channel. 
     Deployment of the Production Assembly within the Well ( 212 ) 
     Referring to  FIG. 9H , once the transition device  44  has been connected to the downhole pump  46 , the portion of the instrumentation lines  50  upstream of the transition device  44  can be clamped onto the exterior of the downhole pump  46  and the pump production line  68 , while the production assembly  102  is deployed into the well  24 . Therefore, once the production assembly  102  has been deployed into the wellbore, the instrumentation lines  50  can extend from the surface  28  downward along the outside of the pump production line  68 , be clamped onto the exterior of the pump  46 , cross inside the transition device  44 , and run down within the guide string  48  to the toe  36  of the well  24 . Depending on the given application, the downhole pump can be located at various locations along the wellbore, for example near the heel  34  of the well  24 . 
     Pump Removal Implementations 
     As mentioned above, according to the techniques described herein, by sealing the instrumentation lines in the transition device, the instrumentation lines can be decoupled from the downhole pump. The decoupling of the pump and instrumentation lines can enable the pump to be removed from the well for inspection, maintenance or replacement without having to pull the instrumentation lines out of the guide string. This can be advantageous when considering that downhole pumps typically require inspection, maintenance or replacement before the instrumentation, and that pulling the instrumentation out of the guide string with unnecessary frequency can subject the instrumentation to risk of damage, which is best reduced or avoided. 
     With reference to  FIG. 16 , a method of removing the downhole pump from the production well for inspection, maintenance or replacement can include several steps that will be explained in further detail below. It is to be noted that in some implementations some of the steps could be performed in a different order than described herein. 
     Removal of the Production Assembly from the Well ( 300 ) 
     Referring to  FIG. 17A , the initial step involves pulling back the production assembly  102  from the production well  24  to bring the downhole pump  46  and transition device  44  to the surface  28  while the guide string  48  remains within the well  24 . 
     Sealing of the Production Well Around the Transition Device ( 302 ) 
     Referring to  FIG. 17B , once the downhole pump  46  and transition device  44  has been removed from the well  24 , the transition device  44  can be positioned partly inside a well blowout preventer  146 , such as a ram blowout preventer or an annulus blowout preventer, or another similar apparatus. Then, the wellbore can be sealed around the outer surface of the transition device  44  by means of the blowout preventer  146 . In this regard, and as mentioned above, the transition device  44  can include an upper pup joint  106  that is sized and configured to provide a surface against which the packing unit  148  of the blowout preventer  146  can be press-fitted to seal the annulus between the outer surface of the upper pup joint  106  and the inner surface of the wellbore in order to ensure well fluid containment when the pump  46  is pulled to the surface for inspection, maintenance or replacement. 
     Testing of the Integrity of the Seal Around the Instrumentation Lines ( 304 ) 
     The integrity of the seal around the instrumentation lines  50  can be verified by using a pressure-test port provided on the sealing assembly. In the event the pressure test is not successful, the packing elements of the sealing assembly can be removed for inspection, maintenance or replacement. Then, once the seal around the instrumentation lines  50  is confirmed, the fluid pathways through and around the transition device  44  sitting at the wellhead are both hermetically sealed, the well  24  is secured against accidental blowout while the pump  46  is sitting at the surface  28 . 
     Reconnection of the Pump to the Transition Device ( 306 ) 
     Referring to  FIG. 17C , once the downhole pump  46  has been inspected or maintained, the pump  46  can be reconnected to the transition device  44 , as explained further above. Alternatively, in the event the pump  46  needed replacement, a replacement downhole pump  46  can be connected to the transition device  44  in replacement of the previous downhole pump. 
     Redeployment of the Production Assembly Back into the Production Well ( 308 ) 
     Referring to  FIG. 17D , once the inspection, maintenance or replacement of the downhole pump has been completed, the packing unit  148  of the blowout preventer  146  can be activated in an open position to release the transition device  44 . Then, the production assembly  102  can be deployed into the wellbore. 
     Various modifications can be made to the disclosed implementations and still be within the scope of the following claims.