CA2848664C

CA2848664C - In situ hydrocarbon recovery using slave string

Info

Publication number: CA2848664C
Application number: CA2848664A
Authority: CA
Inventors: John Graham; Micaela Streeter; Rick Stahl; Jennifer Smith; Dave Kennedy
Original assignee: Suncor Energy Inc
Current assignee: Suncor Energy Inc
Priority date: 2013-04-12
Filing date: 2014-04-09
Publication date: 2016-07-05
Anticipated expiration: 2034-04-09
Also published as: CA2848664A1

Abstract

Hydrocarbon recovery can involve operating a horizontal production well with slave string extending the length of the well and configured to have a first portion for accommodating a downhole pump and a second portion positioned within a slotted liner. A first annulus is formed surrounding the first portion; a second annulus is formed between the liner and the second portion, and the annuli are fluidly connected. A first flow path through the slave string is fluidly connected a second flow path formed through the first and second annuli. Instrumentation can also be connected to the slave string. In startup mode, steam can be injected from surface through the first flow path, past the pump, to enter the second annulus. After startup, the well is put on production mode. The downhole pump and the instrumentation can be left in place when switching from startup to production mode, thereby reducing recompletion.

Description

IN SITU HYDROCARBON RECOVERY USING SLAVE STRING
TECHNICAL FIELD
[0001] The technical field generally relates to in situ hydrocarbon recovery operations, such as Steam-Assisted Gravity Drainage (SAGD), and more particularly to techniques involving well completion as well as well equipment installation and operation for enhanced in situ hydrocarbon recovery.
BACKGROUND

[0002] 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.

[0003] One technique, called Steam-Assisted Gravity Drainage (SAGD), has become a widespread process for recovering heavy oil and/or 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 an injection well and the lower underlying horizontal well is a production well.

[0004] SAGD operation typically begins in a startup mode, in order to establish fluid communication between the injection well and the production well. Often, the initial completion of a SAGD production well for startup mode includes configurations for steam circulation and/or bullheading.

[0005] Steam circulation can be conducted by means of a long steam supply string extending from the surface to the toe of the production well. The steam flows through the steam supply string to the toe of the well and then circulates back toward the heel of the well though an annular space defined between the steam supply string and a surrounding liner. Steam return to the surface is facilitated by means of a shorter steam return string which may have an inlet proximate to the liner hanger and extends upward to the surface.

[0006] Bullheading involves steam injection into the well via the long and short strings or via a single steam supply string that may be provided down the well. In some scenarios, due to reservoir characteristics bullheading may not be the preferred startup mode. In addition, in some scenarios startup can initially be conducted using steam circulation to achieve a certain degree of heating before bullheading is conducted.

[0007] After steam circulating and/or bullheading has been conducted, which can typically take about three months for a SAGD production well, the production well can be recompleted for mechanical lift. Mechanical lift involves the installation of a pump to provide the hydraulic force for lifting production fluid to the surface.

[0008] Removing equipment such as one or more steam supply strings prior to installation of production equipment and components, such as a pump and tailpipe, involves a number of challenges. Recompletion to mechanical lift can be time consuming and represents considerable downtime with various associated inefficiencies.
SUMMARY

[0009] In some implementations, there is provided a process for hydrocarbon recovery comprising:
providing a Steam-Assisted Gravity Drainage (SAGD) well pair in a hydrocarbon-containing reservoir, the well pair including an injection well overlying a production well, wherein the production well comprises a substantially vertical section extending from surface downward and a substantially horizontal section under the surface, wherein a casing is provided within at least the vertical section;
providing a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;
providing a slave string extending substantially a length of the production well from the surface to a toe of the horizontal section, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section of the well; and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli;
providing an electric submersible pump (ESP) within the first slave string portion;
providing instrumentation within the wellbore configured to measure at least one operational characteristic of the production well, the instrumentation being deployed within the production well outside the slave string;
operating the production well in a startup mode to achieve fluid communication between the production well and the injection well, wherein the startup mode corn prises:
injecting steam from surface through the first flow path formed in the slave string, past the ESP to the toe of the horizontal section, and wherein steam is present in the second flow path formed in the first and second annuli; and operating the production well in production mode wherein the ESP is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.

(00010] In some implementations, the instrumentation is attached to an exterior surface of the slave string,

[00011] In some implementations, the instrumentation is configured to measure temperature and pressure within the wellbore.

[00012] In some implementations, the startup mode comprises steam circulation where steam present in the second flow path is recirculated back to the surface.

[00013] In some implementations, the startup mode comprises bullheading where steam present in the second flow path is directed into the reservoir.

[00014] In some implementations, the process includes ceasing the startup mode upon achieving fluid communication between the production well and the injection well.

[00015] In some implementations, the production mode is initiated directly after ceasing the startup mode, without recompletion or rig mobilization activities.

[00016] In some implementations, the instrumentation of the production well remains in place during switching of the production well from the startup mode to the production mode.

[00017] In some implementations, the process includes removing the ESP from the production well for inspection, maintenance or replacement, wherein the instrumentation of the production well remains in place during removal of the ESP.

[00018] In some implementations, there is provided a process for hydrocarbon recovery comprising:
operating a production well in startup mode, wherein the production well is located in a hydrocarbon-containing reservoir and comprises:
a first well section extending from a surface into the reservoir and accommodating a downhole pump; and a second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner and a slave string located within the liner, the slave string comprising:
a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected to a second flow path formed through the first and second annuli;
wherein the startup mode comprises:
injecting a startup fluid from surface through the first flow path formed in the slave string, past the downhole pump, and entering the second annulus;
ceasing injection of the startup fluid; and operating the production well in production mode wherein the downhole pump is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.

[00019] In some implementations, the production well is part of a Steam-Assisted Gravity Drainage (SAGD) well pair including an overlying injection well.

[00020] In some implementations, the production well is an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs.

[00021] In some implementations, the production well is a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

[00022] In some implementations, the first well section comprises: a substantially vertical well section extending from the surface; and a curved intermediate well section fluidly connecting the substantially vertical well section to the substantially horizontal well section.

[00023] In some implementations, the first well section further comprises a casing, and a proximal end of the liner is connected to the casing.

[00024] In some implementations, the first slave string portion is located within the casing and the first annulus is formed between an inner surface of the casing and an outer surface of the first slave string portion.

[00025] In some implementations, the downhole pump is located within the curved intermediate well section or within part of the substantially horizontal well section upstream of the liner.

[00026] In some implementations, the liner extends to a toe of the substantially horizontal well section.

[00027] In some implementations, the second slave string portion extends to a toe of the substantially horizontal well section.

[00028] In some implementations, the downhole pump is an electric submersible pump (ESP).

[00029] In some implementations, the startup mode comprises fluid circulation where startup fluid present in the second flow path is recirculated back to the surface.

[00030] In some implementations, the startup mode comprises bullheading where startup fluid present in the second flow path is directed into the reservoir.

[00031] In some implementations, the process includes ceasing the startup mode upon achieving a pre-determined mobilization characteristic of hydrocarbons in the reservoir.

[00032] In some implementations, the production mode is initiated directly after ceasing the startup mode, without recompletion or rig mobilization activities.

[00033] In some implementations, an instrumentation line is deployed within the well outside the slave string.

[00034] In some implementations, the instrumentation line is attached to an exterior surface of the first and second slave string portions.

[00035] In some implementations, the instrumentation line comprises instrumentation configured to measure temperature.

[00036] In some implementations, the instrumentation line comprises instrumentation configured to measure pressure.

[00037] In some implementations, the instrumentation line extends from the surface to the toe of the substantially horizontal well section.

[00038] In some implementations, the instrumentation line remains in place during switching of the production well from the startup mode to the production mode.

[00039] In some implementations, the process includes removing the downhole pump from the production well for inspection, maintenance or replacement, wherein the instrumentation line remains in place during removal of the downhole pump.

[00040] In some implementations, the startup fluid comprises steam. In some implementations, the startup fluid comprises hot water. In some implementations, the startup fluid comprises organic solvent. In some implementations, the startup fluid comprises chemical reactants. In some implementations, the startup fluid comprises gas vapor.

[00041] In some implementations, the startup fluid is injected at a fluid temperature of at least about 200 C, and the downhole pump is configured to be temperature resistant to at least about 250 C.

[00042] In some implementations, the process includes injecting a blanket gas from the surface into a portion of the first annulus. In some implementations, the blanket gas provides insulation between the slave string and adjacent components of the production well.

[00043] In some implementations, there is provided a completion method for completing a production well located in a hydrocarbon-containing reservoir, the production well comprising a first well section extending from a surface into the reservoir and a second section second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner, the completion method comprising:
deploying a slave string within a wellbore, the slave string comprising:
a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
wherein the first flow path is configured:
to receive a startup fluid from the surface to flow therethrough and past a downhole pump located within the first slave string portion, and into the second annulus; and to receive production fluids from the second annulus upon activation of the downhole pump for transferring the production fluids to the surface.

[00044] In some implementations, the method includes deploying an instrumentation line within the wellbore.

[00045] In some implementations, the instrumentation line is deployed outside the slave string.

[00046] In some implementations, the instrumentation line is pre-installed onto an exterior surface of the slave string and is deployed downhole with the slave string.

[00047] In some implementations, the instrumentation line extends an entire length of the well.

[00048] In some implementations, the downhole pump is pre-installed into the first slave string portion and is deployed downhole with the slave string.

[00049] In some implementations, the production well is part of a Steam-Assisted Gravity Drainage (SAGD) well pair including an overlying injection well.

[00050] In some implementations, the production well is an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs.

[00051] In some implementations, the production well is a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

[00052] In some implementations, the first well section comprises: a substantially vertical well section extending from the surface; and a curved intermediate well section fluidly connecting the substantially vertical well section to the substantially horizontal well section.

[00053] In some implementations, the first well section further comprises a casing, and a proximal end of the liner is connected to the casing.

[00054] In some implementations, the step of deploying the slave string comprises:
locating the first slave string portion within the casing so that the first annulus is formed between an inner surface of the casing and an outer surface of the first slave string portion.

[00055] In some implementations, the downhole pump is located within the curved intermediate well section or within part of the substantially horizontal well section upstream of the liner.

[00056] In some implementations, the liner extends to a toe of the substantially horizontal well section.

[00057] In some implementations, the second slave string portion extends to a toe of the substantially horizontal well section.

[00058] In some implementations, the downhole pump is an electric submersible pump (ESP).

[00059] In some implementations, there is provided a production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:
10 a substantially vertical section extending from a surface downward and a substantially horizontal section under the surface, and an intermediate section between the horizontal section and vertical section;
a casing provided within at least the vertical section;
a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;
a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section and the intermediate section, and ending upstream of the liner hanger;
and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a submersible pump positioned within the first slave string portion;
wherein a fluid is injectable from the surface through the first flow path formed in the slave string and into the reservoir during a startup mode, the fluid being injectable past the submersible pump and flowable in the second flow path formed in the first and second annuli.

[00060] In some implementations, the production well is operable in a production mode upon achieving fluid communication between the production well and the hydrocarbon-containing reservoir; and the submersible pump is operable to provide mechanical lift of hydrocarbon-containing fluid entering the production well through the liner and second slave string portion to pump the hydrocarbon-containing fluid to the surface.

[00061] In some implementations, the production includes instrumentation attached to an exterior surface of the slave string.

[00062] In some implementations, the instrumentation is provided as an instrumentation line attached along the first slave string portion and the second slave string portion.

[00063] In some implementations, the instrumentation is configured to remain in place upon switching of modes between the startup mode and the production mode.

[00064] In some implementations, the instrumentation is configured to remain in place upon removal of the submersible pump for maintenance, inspection or replacement.

[00065] In some implementations, the submersible pump is configured to remain in place upon switching of modes between the startup mode and the production mode.

[00066] In some implementations, the production well is configured as part of a Steam-Assisted Gravity Drainage (SAGD) well pair and underlying a SAGD injection well.

[00067] In some implementations, the production well is configured as an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs.

[00068] In some implementations, the production well is configured as a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

[00069] In some implementations, the first and second flow paths are sized and configured to accommodate flow of startup fluid comprising steam, hot water, organic solvent and/or chemical reactants.

[00070] In some implementations, the production well includes at least one flow control device provided on the second slave string portion configured to control startup fluid flows and/or production fluid flows.

[00071] In some implementations, the production well includes at least one isolation device provided in the second annulus and configured to isolate a corresponding segment of the horizontal portion.

[00072] In some implementations, the production well includes a cross-over portion connecting the first slave string portion with the second slave string portion.

[00073] In some implementations, the submersible pump is an electric submersible pump (ESP) connected to a pump tubing that is located inside the slave string and extends to the surface.
In some implementations, the slave string is composed of a metallic material.
In some implementations, there is provided a production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:
a horizontal wellbore section extending through the reservoir;
a liner located in the horizontal wellbore section, the liner having a proximal end and an distal end;
a downhole pump located upstream of the proximal end of the liner;
a slave string comprising:
a first slave string portion extending from a surface of the reservoir to upstream of the liner, the first slave string portion housing the downhole pump and defining a first annulus surrounding an outer surface of the first slave string portion; and a second slave string portion extending from a distal end of the first slave string portion within the liner, the second slave string portion defining a second annulus surrounding an outer surface thereof and being in fluid communication with the first annulus;
a first flow path defined through the slave string;
a second flow path defined by the first annulus and the second annulus, the second flow path being in fluid communication with the first flow path at a distal end of the slave string, thereby enabling a fluid to flow:
from the surface through the first flow path, past the downhole pump, to the distal end of the slave string and into the second flow path, in startup mode; and from the second annulus, through the distal end of the slave string, and along the first flow path to the surface, in production mode.

[00074] In some implementations, there is provided a startup-and-production completion assembly for deployment and use in a production well having a first well section extending from the surface into the reservoir and a second substantially horizontal well section, comprising:
a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the first well section, and being configured to accommodate a submersible pump; and a second slave string portion with a second outer diameter in the horizontal well section of the production well, the second outer diameter being smaller than the first outer diameter and sized to enable insertion of the second slave string portion into a liner provided in the horizontal well section, wherein the slave string is further sized and configured such that:

a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the second slave string portion and the liner; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a fluid is injectable from the surface through the first flow path formed in the slave string and into the reservoir during a startup mode, the fluid being injectable past the submersible pump and flowable in the second flow path formed in the first and second annuli; and an instrumentation line deployed within the production well outside of the slave string.

[00075] In some implementations, the instrumentation line is attached to an exterior surface of the slave string.

[00076] In some implementations, the startup-and-production completion assembly is configured for use in a Steam-Assisted Gravity Drainage (SAGD) well pair and underlying a SAGD injection well.

[00077] In some implementations, the startup-and-production completion assembly is configured for use in an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs.

[00078] In some implementations, the startup-and-production completion assembly is configured for use in a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

[00079] In some implementations, the first slave string portion and the second slave string portion are sized and configured to provide the first and second flow paths to accommodate flow of startup fluid comprising steam, hot water, organic solvent and/or chemical reactants.

[00080] In some implementations, the assembly includes at least one flow control device provided on the second slave string portion configured to control startup fluid flows and/or production fluid flows.

[00081] In some implementations, the assembly includes at least one isolation device provided in the second annulus and configured to isolate a corresponding segment of the horizontal portion.

[00082] In some implementations, the assembly includes a cross-over portion connecting the first slave string portion with the second slave string portion.

[00083] In some implementations, the slave string is composed of a metallic material.

[00084] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir, comprising:
drilling a pair of Steam-Assisted Gravity Drainage (SAGD) wellbores comprising an injection wellbore and a production wellbore;
completing the pair of SAGD wellbores, comprising:
deploying injection completion equipment into the injection wellbore to provide a SAGD injection well;
deploying production completion equipment into the production wellbore to provide a SAGD production well, comprising:
providing a surface casing;
providing an intermediate casing extending into the wellbore from surface to a heel of SAGD production well;
deploying a liner connected to a distal end of the intermediate casing via a liner hanger, the liner extending to a toe of the SAGD
production well;
deploying a slave string comprising a first slave string portion within the intermediate case, and a second slave string portion within the liner and extending to the toe of the SAGD production well, wherein:
a first annulus is formed between the intermediate casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
deploying an electric submersible pump (ESP) within the first slave string portion; and deploying an instrumentation line outside of the slave string;
operating the SAGD well pair in startup mode comprising:
injecting a startup fluid into the slave string via the first flow path to mobilize hydrocarbons in the reservoir and enable fluid communication between the production well and the injection well; and monitoring characteristics of startup operations with the instrumentation line; and operating the SAGD well pair in production mode directly after the startup mode and without recompleting, comprising:
activating the ESP to provide hydraulic force to produce mobilized hydrocarbons; and monitoring characteristics of production operations with the instrumentation line.

[00085] In some implementations, the instrumentation line is connected to an outer surface of the slave string.

[00086] In some implementations, the startup mode comprises fluid circulation where startup fluid present in the second flow path is recirculated back to the surface.

[00087] In some implementations, the startup mode comprises bullheading where startup fluid present in the second flow path is directed into the reservoir.

[00088] In some implementations, the instrumentation line comprises instrumentation configured to measure temperature.
[00088a] In some implementations, the instrumentation line comprises instrumentation configured to measure pressure.
[00088b] In some implementations, the instrumentation line extends from the surface to the toe of the substantially horizontal well section.
[00088c] In some implementations, the process includes removing the downhole pump from the production well for inspection, maintenance or replacement, wherein the instrumentation line remains in place during removal of the downhole pump.
[00088d] In some implementations, the startup fluid comprises steam. In some implementations, the startup fluid comprises hot water. In some implementations, the startup fluid comprises organic solvent. In some implementations, the startup fluid comprises chemical reactants. In some implementations, the startup fluid comprises gas vapor.
[00088e] In some implementations, the startup fluid is injected at a fluid temperature of at least about 200 C, and the downhole pump is configured to be temperature resistant to at least about 250 C.
[00088f] In some implementations, the process includes injecting a blanket gas from the surface into a portion of the first annulus. In some implementations, the blanket gas provides insulation between the slave string and adjacent components of the production well. In some implementations, the blanket gas is injected during the production mode and/or during bullheading startup mode.
[00088g] In some implementations, there is provided a process for hydrocarbon recovery comprising:

17a providing a Steam-Assisted Gravity Drainage (SAGD) well pair in a hydrocarbon-containing reservoir, the well pair including an injection well overlying a production well, wherein the production well comprises a substantially vertical section extending from surface downward and a substantially horizontal section under the surface, wherein a casing is provided within at least the vertical section;
providing a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;
providing a slave string extending substantially a length of the production well from the surface to a toe of the horizontal section, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section of the well; and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli;
providing an electric submersible pump (ESP) within the first slave string portion;
providing instrumentation along a length of the slave string, the instrumentation being configured to measure at least one operational characteristic of the production well;

1 7b operating the production well in a startup mode to achieve fluid communication between the production well and the injection well, wherein the startup mode comprises:
injecting steam from surface through the second flow path formed in the first and second annuli, and recirculating the steam through the first flow path formed in the slave string, past the ESP back to the surface; and operating the production well in production mode wherein the ESP is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.
[00088h] In some implementations, there is provided a process for hydrocarbon recovery comprising:
operating a production well in startup mode, wherein the production well is located in a hydrocarbon-containing reservoir and comprises:
a first well section extending from a surface into the reservoir and accommodating a downhole pump; and a second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner and a slave string located within the liner, the slave string comprising:
a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed surrounding the first slave string portion;

17c a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
wherein the startup mode comprises:
injecting steam from surface through the second flow path formed in the first and second annuli, and recirculating the steam through the first flow path formed in the slave string, past the downhole pump back to the surface;
ceasing injection of the startup fluid; and operating the production well in production mode wherein the downhole pump is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.
[00088i] In some implementations, there is provided a completion method for completing a production well located in a hydrocarbon-containing reservoir, the production well comprising a first well section extending from a surface into the reservoir and a second section second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner, the completion method comprising:
deploying a slave string within a wellbore, the slave string comprising:
a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:

17d a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
wherein the second flow path is configured:
to receive a startup fluid from the surface to flow therethrough;
and wherein the first flow path is configured:
to recirculate the startup fluid past a downhole pump located within the first slave string portion, back to the surface; and to receive production fluids from the second annulus upon activation of the downhole pump for transferring the production fluids to the surface.
[00088j] In some implementations, there is provided a production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:
a substantially vertical section extending from a surface downward and a substantially horizontal section under the surface, and an intermediate section between the horizontal section and vertical section;
a casing provided within at least the vertical section;
a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;

17e a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section and the intermediate section, and ending upstream of the liner hanger;
and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a submersible pump positioned within the first slave string portion;
wherein a fluid is injectable from the surface through the second flow path formed through the first and second annuli and into the reservoir during a startup mode, the fluid being flowable in the first flow path formed in the slave string past the submersible pump back to the surface.
[00088k] In some implementations, there is provided a production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:
a horizontal wellbore section extending through the reservoir;
a liner located in the horizontal wellbore section, the liner having a proximal end and an distal end;

17f a downhole pump located upstream of the proximal end of the liner;
a slave string comprising:
a first slave string portion extending from a surface of the reservoir to upstream of the liner, the first slave string portion housing the downhole pump and defining a first annulus surrounding an outer surface of the first slave string portion; and a second slave string portion extending from a distal end of the first slave string portion within the liner, the second slave string portion defining a second annulus surrounding an outer surface thereof and being in fluid communication with the first annulus;
a first flow path defined through the slave string;
a second flow path defined by the first annulus and the second annulus, the second flow path being in fluid communication with the first flow path at a distal end of the slave string, thereby enabling a fluid to flow:
from the surface through the second flow path, into the first flow path past the downhole pump, and back to the surface, in startup mode; and from the second annulus, through the distal end of the slave string, and along the first flow path to the surface, in production mode.
[000881] In some implementations, there is provided a startup-and-production completion assembly for deployment and use in a production well having a first well section extending from the surface into the reservoir and a second substantially horizontal well section, comprising:
a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the first well section, and being configured to accommodate a submersible pump; and 17g a second slave string portion with a second outer diameter in the horizontal well section of the production well, the second outer diameter being smaller than the first outer diameter and sized to enable insertion of the second slave string portion into a liner provided in the horizontal well section, wherein the slave string is further sized and configured such that:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the second slave string portion and the liner; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a fluid is injectable from the surface through the second flow path formed through the first and second annuli and into the reservoir during a startup mode, the fluid being flowable in the first flow path formed in the slave string past the submersible pump back to the surface; and an instrumentation line extending along a length of the slave string.
100088m] In some implementations, there is provided a process for recovering hydrocarbons from a reservoir, comprising:
drilling a pair of Steam-Assisted Gravity Drainage (SAGD) wellbores comprising an injection wellbore and a production wellbore;
completing the pair of SAGD wellbores, comprising:
deploying injection completion equipment into the injection wellbore to provide a SAGD injection well;
deploying production completion equipment into the production wellbore to provide a SAGD production well, comprising:
providing a surface casing;

17h providing an intermediate casing extending into the wellbore from surface to a heel of SAGD production well;
deploying a liner connected to a distal end of the intermediate casing via a liner hanger, the liner extending to a toe of the SAGD
production well;
deploying a slave string comprising a first slave string portion within the intermediate case, and a second slave string portion within the liner and extending to the toe of the SAGD production well, wherein:
a first annulus is formed between the intermediate casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
deploying an electric submersible pump (ESP) within the first slave string portion; and deploying an instrumentation line along a length of the slave string;
operating the SAGD well pair in startup mode comprising:
injecting a startup fluid via the second flow path to mobilize hydrocarbons in the reservoir and enable fluid communication between the production well and the injection well; and monitoring characteristics of startup operations with the instrumentation line; and operating the SAGD well pair in production mode directly after the startup mode and without recompleting, comprising:
activating the ESP to provide hydraulic force to produce mobilized hydrocarbons; and monitoring characteristics of production operations with the instrumentation line.
BRIEF DESCRIPTION OF THE DRAWINGS

[00089] Fig 1 is a side cross-sectional view schematic of a SAGD well pair.

[00090] Fig 2 is a front cross-sectional view schematic of SAGD well pairs, an infill well and a step-out well.

[00091] Fig 3 is a side cross-sectional view schematic of a production well including a slave string.

[00092] Fig 4 is a perspective view schematic of part of a slave string.

s

[00093] Figs 5A and 5B are front cross-sectional view schematics of slave strings within respective liners.

[00094] Fig 6 is a side cross-sectional view schematic of a production well including a slave string, in a steam-circulation startup mode.

[00095] Fig 7 is a side cross-sectional view schematic of a production well including a slave string, in another steam-circulation startup mode.

[00096] Fig 8 is a side cross-sectional view schematic of a production well including a slave string, in a bullheading startup mode.

[00097] Fig 9 is a side cross-sectional view schematic of a production well including a slave string, in a production mode.

[00098] Fig 10 is a side cross-sectional view schematic of a production well including a slave string with flow control devices, in a steam-circulation startup mode.

[00099] Fig 11 is a side cross-sectional view schematic of a production well including a slave string with flow control devices, in a production mode.

[000100] Fig 12 is a side cross-sectional view schematic of a startup-and-production (SAP) completion assembly.

[000101] Fig 13 is a process flow diagram.

[000102] Figs 14A to 14C are side cross-sectional view schematics of part of a liner and part of a tailpipe.
DETAILED DESCRIPTION

[000103] Various techniques are described for proceeding directly from startup mode to production mode for a production well in an in situ hydrocarbon recovery operation. By providing a slave string in the production well for receiving a downhole pump and for enabling steam injection through the slave string and past the pump into the production well, production equipment can be pre-installed and present during startup mode and then activated after startup mode to initiate production mode without the need for recompletion activities. In addition, instrumentation can be connected to an external surface of the slave string, enabling the instrumentation to be deployed simultaneously with the slave string and to be decoupled from the downhole pump.
Various techniques described herein can be referred to as "Direct-to-SAGD" or "D-SAGD" processes, particularly when applied to SAGD production wells.

[000104] In conventional systems, steam is typically injected into a SAGD
production well during startup to achieve fluid communication with the injection well and after steam circulation or bullheading is complete, the SAGD production well is converted to mechanical lift. The conversion to mechanical lift can include installation of the downhole pump with an attached instrumentation string, which often takes about seven to twelve days. This time delay has a number of disadvantages, such as dissipation of startup heat leading to a cooler reservoir once production is initiated, and delayed production with the associated economic downside.

[000105] However, in contrast to conventional systems, in some implementations the D-SAGD process enables the downhole pump and the instrumentation to be installed in the production well on day one, avoiding down time of mechanical lift conversion and reducing associated recompletion costs. When the reservoir is ready for production, the downhole pump is already in place and no rig mobilization or recompletion is necessary. In addition, the instrumentation can be decoupled from the downhole pump, allowing the downhole pump to be pulled and replaced without pulling or disrupting the instrumentation, given that the instrumentation is present on the outside of the slave string. There are a number of advantages associated with this arrangement.
For example, the instrumentation is present during startup, so measurements can be obtained immediately rather than waiting until the downhole pump is deployed.
In addition, downhole pumps typically require inspection, maintenance or replacement before the instrumentation, and so the instrumentation string can avoid being pulled with unnecessary frequency as occurs in conventional systems. Pulling the instrumentation can subject the instrumentation to risk of damage, which can be reduced or avoided by decoupling the instrumentation from the downhole pump.

[000106] The concept of using "a tubing within a tubing", through the use of the slave string, provides the production well with more versatility as to different operations and/or functions. In some implementations, the slave string facilitates one or more of the following: steam injection to the toe of a production well; production from the toe of a production well; bullheading or circulation past a pump in a production well;
instrumentation to the toe of a production well with fibre optics or thermocouples;
instrumentation outside the production tubing; and/or thermal insulation of the casing using blanket gas. More regarding the various structural and operational features will be described in greater detail below.
Production well implementations

[000107] Various D-SAGD techniques can be used for various types of SAGD
production wells that require startup. For example, D-SAGD may be used for a production well that is part of a SAGD well pair, or for other production wells such as infill 10 wells or step-out wells that are part of a SAGD operation.
Alternatively, in some implementations, various techniques described herein for startup injection followed by direct production can be used for Cyclic Steam Stimulation (CSS) wells or in situ combustion (ISC) wells.

[000108] Referring to Fig 1, a SAGD operation 10 can include an injection well 12 overlying a production well 14 to form a well pair 16. Each well includes a vertical section extending from the surface 18 into the reservoir 20, and a generally horizontal section that extends within a pay zone of the reservoir 20. The injection well 12 and the production well 14 are separated by an interwell region 22 that is typically immobile at reservoir conditions. During startup mode, the interwell region 22 is mobilized by 20 introducing a mobilizing fluid into one or more of the wells.

[000109] In some implementations, steam is injected into the injection well 12 and the production well 14 to heat the interwell region 22 and mobilize the hydrocarbons to establish fluid communication between the two wells. Other mobilizing fluids, such as organic solvents, may also be used to mobilize the reservoir hydrocarbons by heat and/or dissolution mechanisms. The well pair 16 also has a heel 24 and a toe 26, and it is often desired to circulate the mobilizing fluid along the entire length of the wells. Once the well pair 16 has fluid communication between the two wells, the well pair can covert to normal operation where steam is injected into the injection well 12 and the production well 14 is operated in production mode to supply hydrocarbons to the surface.

[000110] Referring briefly to Fig 2, SAGD well pairs 16 may be arranged in generally parallel relation to each other to form an array of well pairs. As the SAGD

operation progresses, steam chambers 28 form and grow above respective injection wells 12. Infill wells 30 may be drilled, completed and operated in between SAGD well pairs, and step-out wells 32 can be drilled, completed and operated adjacent to one SAGD well pair. In some scenarios, the reservoir regions in which the infill wells 30 or step-out wells 32 are provided can benefit from startup mode involving fluid injection, and thus such wells can utilize D-SAGD techniques.
Well completion and slave string implementations

[000111] Referring to Fig 3, a production well 34 can be drilled, completed and operated in order to transition from startup mode to production mode quickly and without the need for substantial recompletion. The production well 34 includes a slave string 36, which can also be referred to as a "dummy string", which can accommodate deployment of a pump 38 and also enables the injection of a startup fluid, such as steam, past the pump 38 and into the horizontal portion of the well 34 to enable startup operations. More regarding the construction and operation of the slave string 36 will be discussed further below.

[000112] Referring still to Fig 3, the production well 34 includes a surface casing 40 provided at an inlet of the wellbore proximate to the surface, and an intermediate casing 42 provided within the wellbore and extending from the surface downward into the reservoir in the vertical section of the wellbore, in the curved intermediate section or "dogleg" of the wellbore, and in part of the horizontal section of the wellbore at the heel 24. The production well 34 also includes a liner 44 provided in the horizontal portion of the wellbore. The liner 44 can be installed by connection to a distal part of the intermediate casing 42 via a liner hanger 46. The liner 44 can have various constructions including various slot patterns, blank sections, and other features designed for the given application and reservoir characteristics.

[000113] Referring still to Fig 3, the slave string 36 can be installed to extend from the surface within the intermediate casing all the way to the toe 26 of the production well 34. The slave string 36 includes a first portion 48 that extends from the surface to a location that is proximate and upstream of the liner hanger 46, and a second portion 50 that extends from a distal end of the first portion into the liner 44. The slave string 36 can =

also include a cross-over portion 52 in between the first portion 48 and the second portion 50 for transitioning from a larger diameter to a smaller diameter.

[000114] Referring to Fig 4, the first portion 48 and the second portion 50 may be generally tubular structures and the cross-over portion 52 can include plates that are welded or bolted onto the first and second portions to provide a substantially sealed interconnection. The cross-over portion 52 can have various different constructions for joining two tubular elements having different diameters. The cross-over portion 52 can have a disc-like form and be oriented perpendicularly with respect to the first and second portions 48, 50. Alternatively, the cross-over portion 52 can have a generally frusto-conical form and be oriented obliquely with respect to the first and second portions 48, 50. Various other cross-over structures and configurations can be used for transitioning from a larger diameter to a smaller diameter.

[000115] Referring back to Fig 3, the first portion 48 of the slave string 36 is sized and configured to receive the pump 38, which can be an electric submersible pump (ESP). The first portion 48 can be sized to have a first diameter that enables the pump 38 to be deployed downhole and also enables the first portion 48 to define a first annulus 54 between an external surface of the first portion 48 and an inner surface of the intermediate casing 42. More regarding the first annulus 54 will be discussed further below.

[000116] In addition, an instrumentation line 56 can be provided running along an external surface of the slave string 36, and the first portion 48 can have a suitable configuration and size to accommodate the instrumentation line 56 between the external surface of the first portion and the intermediate casing 42. In some implementations, the instrumentation line 56 is clamped to the slave string. There may be one or more instrumentation lines 56 associated with the slave string 36 and configured to measure and transmit data regarding various operational and/or reservoir characteristics before and/or during operation of the production well 34.

[000117] Referring still to Fig 3, the second portion 50 of the slave string 36 can also be referred to as a "tailpipe" and is sized for insertion into the liner 44. The second portion 50 can be sized to have a second diameter enabling insertion into the liner 44 and to define a second annulus 58 between the external surface of the second portion 50 and an inner surface of the liner 44. More regarding the second annulus 58 will be discussed further below. The second portion 50 can extend from a location proximate to and upstream of the liner hanger 46 to the toe of the production well 34, where the second portion 50 has a distal opening 60 through which fluid can flow. The second portion 50 can be installed within the liner 44 with or without corresponding supports.

[000118] In some implementations, the slave string 36 can be made of a metallic material, and is configured to be bendable within the wellbore, as illustrated in the accompanying drawings. Different parts of the slave string 36 can have different constructions and compositions, for example depending on deployment methods and installation locations.
Fluid paths for startup and production

[000119] Referring still to Fig 3, the slave string 36 defines fluid paths to facilitate fluid injection in startup mode as well as fluid recovery in production mode.
A first fluid path 62 is defined in a region including the first annulus 54 and the second annulus 58 that are in fluid communication with each other, while a second fluid path 64 is defined within the first portion 48 and second portion 50 of the slave string 36.

[000120] The first fluid path 62 can be substantially annular from the surface to the toe 26 of the well. The second fluid path 64 can have an annular section from the surface to the pump 38, defined between the inner surface of the first portion 48 of the slave string 36 and an external surface of the pump 38 and associated production line 66, as well as a generally tubular section that extends within the second portion 50 of the slave string 36 and occupies the full volume of the tailpipe.

[000121] The first and second fluid flow paths 62, 64 can be substantially concentric with respect to one another within the wellbore. Given that most components of the well are substantially cylindrical, the flow paths 62, 64 can also have cylindrically annular forms, but each of fluid paths can take on various other annular forms, depending on the particular applications for which the well is intended and the components used to complete the well.

[000122] It should also be noted that the fluid paths 62, 64 defined by annular regions may have a variety of shapes and configurations that may deviate from , , symmetrical or complete annular forms. For example, referring to Fig 5A, the tailpipe 50 can be positioned or oriented within the liner 44 such that, at a given location along the well 34, the tailpipe 50 is located in spaced-apart relation to the liner around the entire circumference of the tailpipe 50, thereby defining a regular complete annulus for the first flow path 62. Such annular flow paths can be symmetrical when the liner 44 and the tailpipe 50 are concentric, or can be acentric when the liner 44 and the tailpipe 50 are offset. Alternatively, referring to Fig 5B, the tailpipe 50 can be positioned or oriented within the liner 44 such that, at a given location along the well 34, part of the tailpipe 50 is in contact with part of the liner 44, thereby defining a crescent-shaped incomplete annulus for the first flow path 62. Supports (not illustrated) can be provided to position the tailpipe 50 or other parts of the slave string 36 in a desired position, thereby defining the cross-sectional shape of the flow paths 62, 64.

[000123] Referring now to Figs 6 to 9, some implementations of startup and production modes will be described. Fig 6 illustrates fluid flow in steam-circulation startup mode, where steam (S) is injected from the surface into the slave string 36.
The steam (S) flows through the second flow path 64 down the vertical section of the well 34 and flows around and past the ESP 38. The steam (S) continues through the second flow path 64 defined within the tailpipe 50 and exits the distal opening 60 to enter the first flow path 62 at the toe 26 of the well 34. The steam (S) then flows back toward the heel 24 of the well 34 within the annular first flow path 62 counter-currently with respect to the steam flowing toward the toe 26 within the tailpipe 50. The steam releases heat into the surrounding reservoir during this steam-circulation process. The steam flowing within the tailpipe 50 can also transfer some heat through the walls of the tailpipe 50 to the steam flowing counter-currently through the surrounding annulus 58. Steam-to-steam heat transfer would be more pronounced proximate the heel 24 of the well compared to the toe 26, which can facilitate heating conformance along the length of the well 34. Once the steam flowing through the first flow path 62 reaches the liner hangers 46, the steam continues back toward the surface and is recuperated as recovered steam (RS).
Recovered steam (RS) can then be heated and converted into injectable steam (S).
Steam circulation can continue in this manner until the desired startup heating has been achieved.

[000124] Fig 7 illustrates an alternative steam-circulation startup mode, where steam (S) is injected from the surface into the first flow path 62 and is recovered via the second flow path 64. This steam-circulation startup mode thus uses reverse flow directions compared to the operation illustrated in Fig 6, and is an optional variation. This optional variation would also benefit from a temperature resistant intermediate casing, since heating of conventional intermediate casings is usually not desirable.

[000125] Fig 8 illustrates fluid flow in bullheading startup mode, where steam (S) is injected from the surface into both the first and second flow paths 62, 64. In some startup operations, both steam circulation and bullheading can be used sequentially.

[000126] Fig 9 illustrates fluid flow during production mode.
Mobilized hydrocarbons flow through slots in the walls of the liner 44 and enter the first fluid flow path 62 defined 10 between the tailpipe 50 and the liner 44. In some scenarios, the production fluids flow through the first fluid flow path 62 toward the toe 26 of the well 34 where the fluid enters the distal opening 60 of the tailpipe 50 and then flows toward the heel 24 of the well via the second fluid flow path 64 within the tailpipe 50. Hydraulic force for enabling displacement of the production fluids is provided by the ESP 38. The production fluids reach and flow into the first portion 48 of slave string 36 and are then supplied by the ESP 38 through the production line 66 to the surface where the production fluids (PF) can be processed.

[000127] Referring briefly to Figs 14A to 14C, the liner 44 and the tailpipe 50 may have various relative configurations such that the distal opening 60 may be located at, 20 beyond, or before the distal end of the tailpipe 50. The tailpipe 50 may also abut against the far end of the wellbore, as shown in Fig 14A, or may be in spaced relation with respect to the end of the wellbore, as shown in Figs 14B and 14C. The tailpipe 50 and the liner 44 may also be placed so that there is an end wellbore region 67 having a pre-determined size to facilitate fluid flows.

[000128] Referring now to Figs 10 and 11, in some implementations the production well 34 can include flow control devices 68 and isolation devices 70 for enabling certain flow characteristics. The isolation devices 70 can include packers for isolating horizontal segments 72A, 72B, 72C of the well 34, and the flow control devices 68 can be regulated to increase or reduce flow at a given segment.

[000129] Fig 10 illustrates fluid flow in steam-circulation startup mode, where steam (S) is injected from the surface into the slave string 36 that includes flow control devices 68 and isolation devices 70. The steam flows into the tailpipe 50 and can flow out of the various flow control devices 68 arranged along the length of the tailpipe 50.
Some steam is returned via the annular flow passage defined between the first portion 48 of the slave string 36 and the intermediate casing 42. The flow control devices 68 can be regulated to focus startup fluid, such as steam, at a desired location along the length of the well to provide targeted heating and mobilization. The targeted heating may be based on various reservoir characteristics, for example. In some scenarios, the flow control devices can be opened by the use of coiled tubing or via control lines. The flow control devices can be configured to be open at the beginning of startup injection operations, and then selected devices can be closed depending on temperature measurements to promote conformance along the well.

[000130] In some scenarios, the isolation devices can be installed before or after startup, although installation prior to startup with the rest of the deployed downhole equipment can avoid completion operations after startup. In some implementations, when installed prior to startup, the isolation devices can be located in the well and are kept in an inactive open configuration to allow fluid communication through the isolation devices during startup operations. The isolation devices can be activated to isolate different segments of the well at some later stage after startup. In some implementations, an additional isolation section can be provided at the heel of the well, and controlled by shutting the return string so that the startup steam would be forced into the heel section.

[000131] Fig 11 illustrates fluid flow in production mode, where production fluids that flow through the slots in the liner 44 will be isolated within a corresponding segment of the liner 44 and be forced to flow into one or more corresponding flow control devices 68 provided in that corresponding segment. The isolation devices 70 can thus be provided in order to divide the first fluid flow path 62 into different segments 72A, 72B, 72C. The flow control devices 68 can have various sizes, constructions and configurations. The flow control devices can be controlled to regulate where production fluid enters the liner from the reservoir, for instance by opening certain flow control devices while closing or restricting others.

Instrumentation implementations

[000132] Referring back to Fig 3, the instrumentation line 56 can be equipped with various devices for detecting or measuring characteristics of the reservoir and/or the process conditions. The instrumentation line 56 can include optical fibers, bubble tubes and/or thermocouples, which can be strapped to the outside of the slave string 36.
Instrumentation can also be provided on an outside portion of the pump 38. The instrumentation line(s) can be configured to enable data acquisition to facilitate evaluation of different parameters, such as temperatures, pressures, flow rates, seismic events, etc., optionally along the entire length of the well 34. The operating conditions during both startup and production modes can be regulated based on the data collected via the instrumentation line 56.

[000133] Deploying the instrumentation line 56 pre-installed onto the slave string 36, can facilitate avoiding time-consuming and impractical recompletion activities that involve deploying instrumentation downhole. In addition, the instrumentation line 56 can be configured and located such that the desired data can be acquired from both startup and production modes, which can include different parameters that are measured and controlled. The instrumentation line 56 can thus be advantageously be configured to be dual-mode.

[000134] In addition, by deploying the instrumentation line 56 pre-installed onto the slave string 36, the instrumentation can remain in the well even in the event the pump 38 has to be pulled for inspection, maintenance or replacement. Other methods that may have installed instrumentation directly to the pump, the associated production line, or on a surface against which the pump may contact when being displaced within or removed from the well. By connecting the instrumentation line 56 to the outside of the slave string 36, the instrumentation can be isolated from the pump 38 and other equipment that deployed within the slave string 36. Instrumentation deployment can thus be independent of ESP deployment.
Electric submersible pump (ESP) implementations

[000135] Referring to Fig 3, the pump 38 can be an electric submersible pump (ESP) configured for deployment within the slave string 36 and can be located at various different locations within the well 34. In some implementations, the ESP 38 is located proximate and just upstream (e.g., a few meters) from the liner hanger 46. The production line 66 includes a tubing through which production fluids can be pumped. In addition, deployment of the ESP can be done by various methods, such as coiled tubing or rig less deployment.

[000136] The ESP 38 is configured to withstand temperatures of the startup mode, which are often higher than the temperatures during production mode. For example, in some implementations the ESP 38 is configured to withstand temperatures of about 250 C so that high-temperature steam can flow past the ESP 38 without incurring damage. When steam is injected at temperatures of about 250 C, the ESP 38 is configured withstand such temperatures. However, in the event that other startup fluids, such as organic solvents, are injected at lower temperatures, the ESP 38 can also be configured to have a lower temperature tolerance compared to high-temperature steam injection. Since the ESP 38 is present within the slave string 36 during startup and production modes, the ESP 38 should be configured to withstand the highest temperature conditions that are to be encountered during both modes. Thus, if a low-temperature solvent-injection startup operation is conducted prior to conventional SAGD
production where the production fluids reach higher temperatures than the startup solvent, a conventional ESP that can withstand the production fluid temperatures can be provided.

[000137] In some implementations, ESP replacement can be reduced to about two days with deployment within the slave string, compared to about five days with conventional systems.
Startup fluid injection implementations

[000138] In some implementations, at least one type of startup fluid is injected into the well 34 during startup mode to mobilize the hydrocarbons. The startup fluid, which can also be referred to as a "mobilizing fluid", can be steam, gas vapor, hot water, diluent or organic solvent (e.g., aromatic compounds such as toluene, xylene, diesel, or naphta; or alkanes such as butane, pentane, hexane or heptane) and/or chemical reactants. The type of startup fluid that is used will depend on various factors and the particular applications and desired end results.

[000139] The startup fluid can be injected using circulation and/or bullheading techniques. The startup fluid can also be allowed to soak within the reservoir between injection cycles and/or prior to initiating the production mode.
Blanket gas implementations

[000140] Referring to Figs 9 and 11, in some implementations a blanket gas (BG) can be injected from the surface into the first annulus 54 during production mode. The blanket gas (BG) can be injected at a pressure sufficient to form a gas-hydrocarbon interface 74 in at a desired location upstream of the liner hanger 46. The blanket gas can be employed for insulating purposes between the intermediate casing 42 and the slave string 36 so that the intermediate casing 42 is protected from elevated temperature conditions.

[000141] In some implementations, the blanket gas (BG) can be injected during startup modes where steam is injected through the second flow path 64 and is not recovered. The blanket gas forms a gas-steam interface approximately where the gas-hydrocarbon interface would be in production mode, thereby protecting the intermediate casing from elevated temperature conditions.
Deployment and completion assembly implementations

[000142] Referring to Fig 12, a startup-and-production (SAP) completion assembly 76 includes the slave string 36, the ESP 38, and the instrumentation line 56.
The SAP
completion assembly 100 can be provided as a pre-assembled apparatus for deployment as a unit into the well. Alternatively, a SAP kit can be provided for partial or complete assembly prior to deployment.

[000143] Still referring to Fig 12, in some implementations the SAP
assembly 76 is provided with pre-determined dimensions based on other well components. The first portion 48 of the slave string 36 can have an internal diameter D11 that is sized to accommodate the ESP having a width of Dp, and an external diameter Del that is sized to form an annulus of sufficient size between the first portion 48 and the intermediate casing (not shown here) for the desired fluid flow implementation that can include startup fluid and/or blanket gas. In addition, the second portion 50, or tailpipe, can have an internal diameter 012 that is provided to accommodate both startup fluid and production fluid flows, and an external diameter De2 that is provided to form an annulus of sufficient size between the second portion 50 and the liner (not shown here). The diameters may be pre-determined based on various factors, such as temperature conditions, pressure conditions, flow rates, friction factors and pressure drops of various fluids to be flowed through the flow paths, and so on. In addition, the diameters can be pre-determined based on well designs that contemplated deploying a SAP assembly 76 for a recovery process including startup and direct-to-production stages, or for well designs that did not initially contemplate such a process.

[000144] Various completion deployment strategies may be undertaken in order to 10 deploy and install a SAP assembly 76 within the production well. In some implementations, the SAP assembly 76 is deployed as a pre-assembled unit. In some implementations, different components may be deployed separately or in sub-combinations. For example, after the liner is installed the slave string 36 and the instrumentation line 56 can be deployed together, followed by the ESP 38 in a separate deployment operation. Alternatively, in some implementations, the tailpipe 50 can be pre-installed within the liner and deployed with the liner, followed by deployment of the second portion 48, which is then attached to the tailpipe downhole using a downhole-connection technique. Various other deployment techniques can also be used depending on the particular construction and interconnection of the components.
20 [000145] Referring now to Fig 13, the hydrocarbon recovery process can include several steps that will be explained in further detail below. Drilling step (100): The initial step is drilling one or more wellbores for the production well. The drilling can be conducted to provide the wellbore with a trajectory that is determined based on various factors including reservoir and process operating characteristics.
[000146] Casing installation step (102): Once the wellbore has been drilled, the surface casing and the intermediate casing can be installed using various techniques.
The intermediate casing can have various configurations and can extend into the wellbore to a location where the liner can be hung and where the pump can be located within part of the slave string. The intermediate casing can extend through the vertical 30 section, the curved dogleg section, and into the proximal part of the horizontal section of the wellbore.

[000147] Liner installation step (104): The liner can be installed in the horizontal section of the wellbore using various techniques. For example, the liner can be installed by connection to a distal part of the intermediate casing located within the horizontal section via a liner hanger. The liner can be sized to extend from the hanger to the toe of the wellbore.
[000148] Slave string installation (106): The slave string is then installed by feeding the tailpipe into the wellbore until the distal opening of the tailpipe is located at the toe of the well and the cross-over portion is just upstream of the liner hanger. The tailpipe can have a predetermined length that is longer than the liner, such that complete insertion of the tailpipe into the liner results in the positioning of the cross-over portion and the first portion of the slave string upstream of the liner hanger within the intermediate casing.
Instrumentation can be connected to an external surface of the slave string, such that the instrumentation and slave string are co-deployed into the wellbore. In addition, flow control devices can also be pre-installed onto the tailpipe of the slave string. Packers may be deployed during the original completion prior to startup steaming.
[000149] ESP deployment (108): The ESP can be deployed downhole into the first portion of the slave string and located at various locations. The ESP can be located proximate to the liner hanger (e.g., a few meters upstream of the liner hanger). There can also be various supports that are used to support the ESP within the slave string, if need be. It should also be noted that the ESP can be deployed after installation of the slave string, or co-deployed with the slave string.
[000150] Startup operations (110): Once the slave string, ESP and instrumentation are deployed, the startup operations can be initiated. For example, steam can be supplied from a Once-Through Steam Generator (OTSG) or another type of boiler for injection via the slave string. As explained in greater detail further above, various fluid circulation and/or bullheading techniques can be employed during startup operations.
When the production well is part of a SAGD well pair, the overlying injection well can also be operated with fluid injection. The instrumentation in the production well can be used to detect whether fluid communication has been achieved between the injection well and the production well. When the production well is an infill well, the instrumentation can be used to detect whether fluid communication has been achieved between the infill well and the surrounding pre-heated hydrocarbons of the existing SAGD operation.
[000151] Stopping startup (112): Once the startup operations have sufficiently mobilized hydrocarbons in the reservoir region proximate to the production well, the startup fluid injection is stopped so that the well can be converted to production mode.
After steaming is terminated, the pump can be allowed to cool to desired pump-startup operating conditions before the pump is activated.
[000152] Production step (114): Production mode can be implemented almost immediately after injection has been stopped. Production can be initiated directly after startup, with minimal to no intermediary steps other than relatively simple valve and ESP
activation. No recompletion or rig mobilization steps are required, since the pump and instrumentation were installed prior to startup.
[000153] Blanket gas step (116): Prior to or during production, a gas source can be supplied into the annulus between the intermediate casing and the external surface of the slave string down to a certain depth of the well, thereby forming a gas blanket as describe above. The blanket gas can also be established at other times depending on the startup operations; for example, the gas blanket can be present during startup when steam is injected into the slave string and not recovered via the annulus between the intermediate casing and the slave string.

Claims

33

1. A process for hydrocarbon recovery comprising:
providing a Steam-Assisted Gravity Drainage (SAGD) well pair in a hydrocarbon-containing reservoir, the well pair including an injection well overlying a production well, wherein the production well comprises a substantially vertical section extending from surface downward and a substantially horizontal section under the surface, wherein a casing is provided within at least the vertical section;
providing a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;
providing a slave string extending substantially a length of the production well from the surface to a toe of the horizontal section, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section of the well; and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli;
providing an electric submersible pump (ESP) within the first slave string portion;

providing instrumentation within the wellbore configured to measure at least one operational characteristic of the production well, the instrumentation being deployed within the production well outside the slave string;
operating the production well in a startup mode to achieve fluid communication between the production well and the injection well, wherein the startup mode comprises:
injecting steam from surface through the first flow path formed in the slave string, past the ESP to the toe of the horizontal section, and wherein steam is present in the second flow path formed in the first and second annuli; and operating the production well in production mode wherein the ESP is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.

2. The process of claim 1, wherein the instrumentation is attached to an exterior surface of the slave string,

3. The process of claim 1 or 2, wherein the instrumentation is configured to measure temperature and pressure within the wellbore.

4. The process of any one of claims 1 through 3, wherein the startup mode comprises steam circulation where steam present in the second flow path is recirculated back to the surface.

5. The process of any one of claims 1 through 4, wherein the startup mode comprises bullheading where steam present in the second flow path is directed into the reservoir.

6. The process of any one of claims 1 to 5, further comprising:

ceasing the startup mode upon achieving fluid communication between the production well and the injection well.

7. The process of claim 6, wherein the production mode is initiated directly after ceasing the startup mode, without recompletion or rig mobilization activities.

8. The process of any one of claims 1 to 7, wherein the instrumentation of the production well remains in place during switching of the production well from the startup mode to the production mode.

9. The process of any one of claims 1 to 8, further comprising:
removing the ESP from the production well for inspection, maintenance or replacement, wherein the instrumentation of the production well remains in place during removal of the ESP.

10. A process for hydrocarbon recovery comprising:
operating a production well in startup mode, wherein the production well is located in a hydrocarbon-containing reservoir and comprises:
a first well section extending from a surface into the reservoir and accommodating a downhole pump; and a second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner and a slave string located within the liner, the slave string comprising:
a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed surrounding the first slave string portion;

a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected to a second flow path formed through the first and second annuli;
wherein the startup mode comprises:
injecting a startup fluid from surface through the first flow path formed in the slave string, past the downhole pump, and entering the second annulus;
ceasing injection of the startup fluid; and operating the production well in production mode wherein the downhole pump is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.

11. The process of claim 10, wherein the production well is part of a Steam-Assisted Gravity Drainage (SAGD) well pair including an overlying injection well.

12. The process of claim 10, wherein the production well is an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs.

13. The process of claim 10, wherein the production well is a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

14. The process of any one of claims 10 to 13, wherein the first well section comprises:
a substantially vertical well section extending from the surface; and a curved intermediate well section fluidly connecting the substantially vertical well section to the substantially horizontal well section.

15. The process of claim 14, wherein the first well section further comprises a casing, and a proximal end of the liner is connected to the casing.

16. The process of claim 15, wherein the first slave string portion is located within the casing and the first annulus is formed between an inner surface of the casing and an outer surface of the first slave string portion.

17. The process of any one of claims 14 to 16, wherein the downhole pump is located within the curved intermediate well section or within part of the substantially horizontal well section upstream of the liner.

18. The process of any one of claims 10 to 17, wherein the liner extends to a toe of the substantially horizontal well section.

19. The process of any one of claims 10 to 17, wherein the second slave string portion extends to a toe of the substantially horizontal well section.

20. The process of any one of claims 10 to 19, wherein the downhole pump is an electric submersible pump (ESP).

21. The process of any one of claims 10 to 20, wherein the startup mode comprises fluid circulation where startup fluid present in the second flow path is recirculated back to the surface.

22. The process of any one of claims 10 to 21, wherein the startup mode comprises bullheading where startup fluid present in the second flow path is directed into the reservoir.

23. The process of any one of claims 10 to 22, further comprising:
ceasing the startup mode upon achieving a pre-determined mobilization characteristic of hydrocarbons in the reservoir.

24. The process of claim 23, wherein the production mode is initiated directly after ceasing the startup mode, without recompletion or rig mobilization activities.

25. The process of any one of claims 10 to 24, wherein an instrumentation line is deployed within the well outside the slave string.

26. The process of claim 25, wherein the instrumentation line is attached to an exterior surface of the first and second slave string portions.

27. The process of claim 26, wherein the instrumentation line comprises instrumentation configured to measure temperature.

28. The process of claim 26 or 27, wherein the instrumentation line comprises instrumentation configured to measure pressure.

29. The process of any one of claims 26 to 28, wherein the instrumentation line extends from the surface to the toe of the substantially horizontal well section.

30. The process of any one of claims 26 to 28, wherein the instrumentation line remains in place during switching of the production well from the startup mode to the production mode.

31. The process of any one of claims 26 to 30, further comprising:
removing the downhole pump from the production well for inspection, maintenance or replacement, wherein the instrumentation line remains in place during removal of the downhole pump.

32. The process of any one of claims 10 to 31, wherein the startup fluid comprises steam.

33. The process of any one of claims 10 to 32, wherein the startup fluid comprises hot water.

34. The process of any one of claims 10 to 33, wherein the startup fluid comprises organic solvent.

35. The process of any one of claims 10 to 34, wherein the startup fluid comprises chemical reactants.

36. The process of any one of claims 10 to 35, wherein the startup fluid comprises gas vapor.

37. The process of any one of claims 10 to 32, wherein the startup fluid is injected at a fluid temperature of at least about 200°C, and the downhole pump is configured to be temperature resistant to at least about 250°C.

38. The process of any one of claims 10 to 20, further comprising:
injecting a blanket gas from the surface into a portion of the first annulus.

39. The process of claim 38, wherein the blanket gas provides insulation between the slave string and adjacent components of the production well.

40. A completion method for completing a production well located in a hydrocarbon-containing reservoir, the production well comprising a first well section extending from a surface into the reservoir and a second section second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner, the completion method comprising:
deploying a slave string within a wellbore, the slave string comprising:
a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
wherein the first flow path is configured:

to receive a startup fluid from the surface to flow therethrough and past a downhole pump located within the first slave string portion, and into the second annulus; and to receive production fluids from the second annulus upon activation of the downhole pump for transferring the production fluids to the surface.

41. The process of claim 40, further comprising: deploying an instrumentation line within the wellbore.

42. The process of claim 41, wherein the instrumentation line is deployed outside the slave string.

43. The process of claim 41 or 42, wherein the instrumentation line is pre-installed onto an exterior surface of the slave string and is deployed downhole with the slave string.

44. The process of any one of claims 41 through 43, wherein the instrumentation line extends an entire length of the well.

45. The process of any one of claims 40 through 44, wherein the downhole pump is pre-installed into the first slave string portion and is deployed downhole with the slave string.

46. The process of any one of claims 40 to 45, wherein the production well is part of a Steam-Assisted Gravity Drainage (SAGD) well pair including an overlying injection well.

47. The process of any one of claims 40 to 45, wherein the production well is an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs.

48. The process of any one of claims 40 to 45, wherein the production well is a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

49. The process of any one of claims 40 to 48, wherein the first well section comprises:
a substantially vertical well section extending from the surface; and a curved intermediate well section fluidly connecting the substantially vertical well section to the substantially horizontal well section.

50. The process of claim 49, wherein the first well section further comprises a casing, and a proximal end of the liner is connected to the casing.

51. The process of claim 50, wherein the step of deploying the slave string comprises:
locating the first slave string portion within the casing so that the first annulus is formed between an inner surface of the casing and an outer surface of the first slave string portion.

52. The process of any one of claims 49 to 51, wherein the downhole pump is located within the curved intermediate well section or within part of the substantially horizontal well section upstream of the liner.

53. The process of any one of claims 40 to 52, wherein the liner extends to a toe of the substantially horizontal well section.

54. The process of any one of claims 40 to 52, wherein the second slave string portion extends to a toe of the substantially horizontal well section.

55. The process of any one of claims 40 to 54, wherein the downhole pump is an electric submersible pump (ESP).

56. A production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:
a substantially vertical section extending from a surface downward and a substantially horizontal section under the surface, and an intermediate section between the horizontal section and vertical section;
a casing provided within at least the vertical section;
a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;

a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section and the intermediate section, and ending upstream of the liner hanger;
and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a submersible pump positioned within the first slave string portion;
wherein a fluid is injectable from the surface through the first flow path formed in the slave string and into the reservoir during a startup mode, the fluid being injectable past the submersible pump and flowable in the second flow path formed in the first and second annuli.

57. The production well of claim 56, wherein the production well is operable in a production mode upon achieving fluid communication between the production well and the hydrocarbon-containing reservoir; and the submersible pump is operable to provide mechanical lift of hydrocarbon-containing fluid entering the production well through the liner and second slave string portion to pump the hydrocarbon-containing fluid to the surface.

58. The production well of claim 56 or 57, further comprising instrumentation attached to an exterior surface of the slave string.

59. The production well of claim 58, wherein the instrumentation is provided as an instrumentation line attached along the first slave string portion and the second slave string portion

60. The production well of claim 58 or 59, wherein the instrumentation is configured to remain in place upon switching of modes between the startup mode and the production mode.

61. The production well of any one of claims 58 to 60, wherein the instrumentation is configured to remain in place upon removal of the submersible pump for maintenance, inspection or replacement

62. The production well of any one of claims 56 to 61, wherein the submersible pump is configured to remain in place upon switching of modes between the startup mode and the production mode.

63 The production well of any one of claims 56 to 62, configured as part of a Steam-Assisted Gravity Drainage (SAGD) well pair and underlying a SAGD injection well.

64. The production well of any one of claims 56 to 62, configured as an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs

65. The production well of any one of claims 56 to 62, configured as a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

66. The production well of any one of claims 56 to 65, wherein the first and second flow paths are sized and configured to accommodate flow of startup fluid comprising steam, hot water, organic solvent and/or chemical reactants.

67 The production well of any one of claims 56 to 66, further comprising:
at least one flow control device provided on the second slave string portion configured to control startup fluid flows and/or production fluid flows.

68 The production well of any one of claims 56 to 67, further comprising.
at least one isolation device provided in the second annulus and configured to isolate a corresponding segment of the horizontal portion

69. The production well of any one of claims 56 to 66, further comprising:
a cross-over portion connecting the first slave string portion with the second slave string portion.

70. The production well of any one of claims 56 to 66, wherein the submersible pump is an electric submersible pump (ESP) connected to a pump tubing that is located inside the slave string and extends to the surface.

71. The production well of any one of claims 56 to 66, wherein the slave string is composed of a metallic material.

72. A production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:
a horizontal wellbore section extending through the reservoir;
a liner located in the horizontal wellbore section, the liner having a proximal end and an distal end;
a downhole pump located upstream of the proximal end of the liner;
a slave string comprising:
a first slave string portion extending from a surface of the reservoir to upstream of the liner, the first slave string portion housing the downhole pump and defining a first annulus surrounding an outer surface of the first slave string portion; and a second slave string portion extending from a distal end of the first slave string portion within the liner, the second slave string portion defining a second annulus surrounding an outer surface thereof and being in fluid communication with the first annulus;
a first flow path defined through the slave string;

a second flow path defined by the first annulus and the second annulus, the second flow path being in fluid communication with the first flow path at a distal end of the slave string, thereby enabling a fluid to flow:
from the surface through the first flow path, past the downhole pump, to the distal end of the slave string and into the second flow path, in startup mode; and from the second annulus, through the distal end of the slave string, and along the first flow path to the surface, in production mode.

73. A startup-and-production completion assembly for deployment and use in a production well having a first well section extending from the surface into the reservoir and a second substantially horizontal well section, comprising:
a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the first well section, and being configured to accommodate a submersible pump; and a second slave string portion with a second outer diameter in the horizontal well section of the production well, the second outer diameter being smaller than the first outer diameter and sized to enable insertion of the second slave string portion into a liner provided in the horizontal well section, wherein the slave string is further sized and configured such that:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the second slave string portion and the liner; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a fluid is injectable from the surface through the first flow path formed in the slave string and into the reservoir during a startup mode, the fluid being injectable past the submersible pump and flowable in the second flow path formed in the first and second annuli; and an instrumentation line deployed within the production well outside of the slave string.

74. The startup-and-production completion assembly of claim 73, wherein the instrumentation line is attached to an exterior surface of the slave string.

75. The startup-and-production completion assembly of claim 73 or 74, configured for use in a Steam-Assisted Gravity Drainage (SAGD) well pair and underlying a SAGD
injection well.

76. The startup-and-production completion assembly of claim 73 or 74, configured for use in an infill well located in between two adjacent Steam-Assisted Gravity Drainage (SAGD) well pairs.

77. The startup-and-production completion assembly of claim 73 or 74, configured for use in a step-out well located beside one adjacent Steam-Assisted Gravity Drainage (SAGD) well pair.

78. The startup-and-production completion assembly of any one of claims 73 to 77, wherein the first slave string portion and the second slave string portion are sized and configured to provide the first and second flow paths to accommodate flow of startup fluid comprising steam, hot water, organic solvent and/or chemical reactants.

79. The startup-and-production completion assembly of any one of claims 73 to 78, further comprising:
at least one flow control device provided on the second slave string portion configured to control startup fluid flows and/or production fluid flows.

80. The startup-and-production completion assembly of any one of claims 73 to 79, further comprising:
at least one isolation device provided in the second annulus and configured to isolate a corresponding segment of the horizontal portion.

81. The startup-and-production completion assembly of any one of claims 73 to 80, further comprising:
a cross-over portion connecting the first slave string portion with the second slave string portion.

82. The startup-and-production completion assembly of any one of claims 73 to 81, wherein the slave string is composed of a metallic material.

83. A process for recovering hydrocarbons from a reservoir, comprising:
drilling a pair of Steam-Assisted Gravity Drainage (SAGD) wellbores comprising an injection wellbore and a production wellbore;
completing the pair of SAGD wellbores, comprising:
deploying injection completion equipment into the injection wellbore to provide a SAGD injection well;
deploying production completion equipment into the production wellbore to provide a SAGD production well, comprising:
providing a surface casing;
providing an intermediate casing extending into the wellbore from surface to a heel of SAGD production well;
deploying a liner connected to a distal end of the intermediate casing via a liner hanger, the liner extending to a toe of the SAGD
production well;
deploying a slave string comprising a first slave string portion within the intermediate case, and a second slave string portion within the liner and extending to the toe of the SAGD production well, wherein:
a first annulus is formed between the intermediate casing and the first slave string portion;

a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
deploying an electric submersible pump (ESP) within the first slave string portion; and deploying an instrumentation line outside of the slave string;
operating the SAGD well pair in startup mode comprising:
injecting a startup fluid into the slave string via the first flow path to mobilize hydrocarbons in the reservoir and enable fluid communication between the production well and the injection well; and monitoring characteristics of startup operations with the instrumentation line; and operating the SAGD well pair in production mode directly after the startup mode and without recompleting, comprising:
activating the ESP to provide hydraulic force to produce mobilized hydrocarbons; and monitoring characteristics of production operations with the instrumentation line.

84. The process of claim 83, wherein the instrumentation line is connected to an outer surface of the slave string.

85. The process of claim 83, wherein the startup mode comprises fluid circulation where startup fluid present in the second flow path is recirculated back to the surface.

86. The process of claim 83, wherein the startup mode comprises bullheading where startup fluid present in the second flow path is directed into the reservoir.

87. The process of any one of claims 83 to 86, wherein the instrumentation line comprises instrumentation configured to measure temperature.

88. The process of any one of claims 83 to 87, wherein the instrumentation line comprises instrumentation configured to measure pressure.

89. The process of any one of claims 83 to 88, wherein the instrumentation line extends from the surface to the toe of the substantially horizontal well section.

90. The process of any one of claims 83 to 89, further comprising:
removing the downhole pump from the production well for inspection, maintenance or replacement, wherein the instrumentation line remains in place during removal of the downhole pump.

91. The process of any one of claims 83 to 90, wherein the startup fluid comprises steam.

92. The process of any one of claims 83 to 91, wherein the startup fluid comprises hot water.

93. The process of any one of claims 83 to 92, wherein the startup fluid comprises organic solvent.

94. The process of any one of claims 83 to 93, wherein the startup fluid comprises chemical reactants.

95. The process of any one of claims 83 to 94, wherein the startup fluid comprises gas vapor.

96. The process of any one of claims 83 to 95, wherein the startup fluid is injected at a fluid temperature of at least about 200°C, and the downhole pump is configured to be temperature resistant to at least about 250°C.

97. The process of any one of claims 83 to 96, further comprising:

injecting a blanket gas from the surface into a portion of the first annulus.

98. The process of claim 97, wherein the blanket gas provides insulation between the slave string and adjacent components of the production well.

99. The process of claim 97 or 98, wherein the blanket gas is injected during the production mode and/or during bullheading startup mode.

100. A process for hydrocarbon recovery comprising:
providing a Steam-Assisted Gravity Drainage (SAGD) well pair in a hydrocarbon-containing reservoir, the well pair including an injection well overlying a production well, wherein the production well comprises a substantially vertical section extending from surface downward and a substantially horizontal section under the surface, wherein a casing is provided within at least the vertical section;
providing a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;
providing a slave string extending substantially a length of the production well from the surface to a toe of the horizontal section, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section of the well; and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli;
providing an electric submersible pump (ESP) within the first slave string portion;
providing instrumentation along a length of the slave string, the instrumentation being configured to measure at least one operational characteristic of the production well;
operating the production well in a startup mode to achieve fluid communication between the production well and the injection well, wherein the startup mode comprises:
injecting steam from surface through the second flow path formed in the first and second annuli, and recirculating the steam through the first flow path formed in the slave string, past the ESP back to the surface; and operating the production well in production mode wherein the ESP is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.

101. A process for hydrocarbon recovery comprising:
operating a production well in startup mode, wherein the production well is located in a hydrocarbon-containing reservoir and comprises:
a first well section extending from a surface into the reservoir and accommodating a downhole pump; and a second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner and a slave string located within the liner, the slave string comprising:

a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
wherein the startup mode comprises:
injecting steam from surface through the second flow path formed in the first and second annuli, and recirculating the steam through the first flow path formed in the slave string, past the downhole pump back to the surface ceasing injection of the startup fluid;
and operating the production well in production mode wherein the downhole pump is activated to provide hydraulic force to induce hydrocarbons to flow via the second annulus into the second slave string portion and then through the slave string to the surface.

102. A completion method for completing a production well located in a hydrocarbon-containing reservoir, the production well comprising a first well section extending from a surface into the reservoir and a second section second substantially horizontal well section extending from the first well section into the reservoir, the horizontal well section comprising a liner, the completion method comprising:
deploying a slave string within a wellbore, the slave string comprising:

a first slave string portion with a first outer diameter in the first well section; and a second slave string portion with a second outer diameter in the horizontal well section, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
wherein the second flow path is configured:
to receive a startup fluid from the surface to flow therethrough;
and wherein the first flow path is configured:
to recirculate the startup fluid past a downhole pump located within the first slave string portion, back to the surface; and to receive production fluids from the second annulus upon activation of the downhole pump for transferring the production fluids to the surface.

103. A production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:

a substantially vertical section extending from a surface downward and a substantially horizontal section under the surface, and an intermediate section between the horizontal section and vertical section;
a casing provided within at least the vertical section;
a liner in the horizontal section of the production well, the liner being connected to the casing by a liner hanger;
a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the vertical section and the intermediate section, and ending upstream of the liner hanger;
and a second slave string portion with a second outer diameter in the horizontal section of the production well, the second outer diameter being smaller than the first outer diameter, wherein:
a first annulus is formed between the casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a submersible pump positioned within the first slave string portion;
wherein a fluid is injectable from the surface through the second flow path formed through the first and second annuli and into the reservoir during a startup mode, the fluid being flowable in the first flow path formed in the slave string past the submersible pump back to the surface.

104. A production well for use in hydrocarbon recovery from a hydrocarbon-containing reservoir, the production well comprising:
a horizontal wellbore section extending through the reservoir;
a liner located in the horizontal wellbore section, the liner having a proximal end and an distal end, a downhole pump located upstream of the proximal end of the liner;
a slave string comprising:
a first slave string portion extending from a surface of the reservoir to upstream of the liner, the first slave string portion housing the downhole pump and defining a first annulus surrounding an outer surface of the first slave string portion; and a second slave string portion extending from a distal end of the first slave string portion within the liner, the second slave string portion defining a second annulus surrounding an outer surface thereof and being in fluid communication with the first annulus, a first flow path defined through the slave string;
a second flow path defined by the first annulus and the second annulus, the second flow path being in fluid communication with the first flow path at a distal end of the slave string, thereby enabling a fluid to flow:
from the surface through the second flow path, into the first flow path past the downhole pump, and back to the surface, in startup mode, and from the second annulus, through the distal end of the slave string, and along the first flow path to the surface, in production mode.

105. A startup-and-production completion assembly for deployment and use in a production well having a first well section extending from the surface into the reservoir and a second substantially horizontal well section, comprising:

a slave string extending substantially a length of the production well, wherein the slave string includes:
a first slave string portion with a first outer diameter in the first well section, and being configured to accommodate a submersible pump; and a second slave string portion with a second outer diameter in the horizontal well section of the production well, the second outer diameter being smaller than the first outer diameter and sized to enable insertion of the second slave string portion into a liner provided in the horizontal well section, wherein the slave string is further sized and configured such that:
a first annulus is formed surrounding the first slave string portion;
a second annulus is formed between the second slave string portion and the liner; and a first flow path formed through the slave string is fluidly connected at a toe of the second slave string portion to a second flow path formed through the first and second annuli; and a fluid is injectable from the surface through the second flow path formed through the first and second annuli and into the reservoir during a startup mode, the fluid being flowable in the first flow path formed in the slave string past the submersible pump back to the surface; and an instrumentation line extending along a length of the slave string.

106. A process for recovering hydrocarbons from a reservoir, comprising:
drilling a pair of Steam-Assisted Gravity Drainage (SAGD) wellbores comprising an injection wellbore and a production wellbore;
completing the pair of SAGD wellbores, comprising:
deploying injection completion equipment into the injection wellbore to provide a SAGD injection well;

deploying production completion equipment into the production wellbore to provide a SAGD production well, comprising:
providing a surface casing;
providing an intermediate casing extending into the wellbore from surface to a heel of SAGD production well;
deploying a liner connected to a distal end of the intermediate casing via a liner hanger, the liner extending to a toe of the SAGD
production well;
deploying a slave string comprising a first slave string portion within the intermediate case, and a second slave string portion within the liner and extending to the toe of the SAGD production well, wherein:
a first annulus is formed between the intermediate casing and the first slave string portion;
a second annulus is formed between the liner and the second slave string portion, the second annulus being in fluid communication with the first annulus; and a first flow path formed through the slave string is fluidly connected a second flow path formed through the first and second annuli;
deploying an electric submersible pump (ESP) within the first slave string portion; and deploying an instrumentation line along a length of the slave string;
operating the SAGD well pair in startup mode comprising:
injecting a startup fluid via the second flow path to mobilize hydrocarbons in the reservoir and enable fluid communication between the production well and the injection well; and monitoring characteristics of startup operations with the instrumentation line; and operating the SAGD well pair in production mode directly after the startup mode and without recompleting, comprising:
activating the ESP to provide hydraulic force to produce mobilized hydrocarbons; and monitoring characteristics of production operations with the instrumentation line.