Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02848664 2014-04-09
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.
CA 02848664 2015-09-08
2
[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
CA 02848664 2015-09-08
3
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,
CA 02848664 2015-09-08
4
[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
CA 02848664 2015-09-08
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.
CA 02848664 2015-09-08
6
[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.
CA 02848664 2015-09-08
7
[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.
CA 02848664 2015-09-08
8
[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.
CA 02848664 2015-09-08
9
[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.
CA 02848664 2015-09-08
[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
CA 02848664 2015-09-08
11
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.
CA 02848664 2015-09-08
12
[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
CA 02848664 2015-09-08
13
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:
CA 02848664 2015-09-08
14
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.
CA 02848664 2015-09-08
[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.
10
[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
CA 02848664 2015-09-08
16
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.
CA 02848664 2015-09-08
17
[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:
CA 02848664 2015-09-08
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;
CA 02848664 2015-09-08
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;
CA 02848664 2015-09-08
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:
CA 02848664 2015-09-08
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;
CA 02848664 2015-09-08
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;
CA 02848664 2015-09-08
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
CA 02848664 2015-09-08
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;
CA 02848664 2015-09-08
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
CA 02848664 2015-09-08
171
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.
CA 02848664 2014-04-09
s
18
[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
CA 02848664 2014-04-09
19
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
CA 02848664 2014-04-09
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
CA 02848664 2014-04-09
21
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
CA 02848664 2014-04-09
=
22
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
CA 02848664 2014-04-09
23
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
CA 02848664 2014-04-09
,
,
24
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
CA 02848664 2014-04-09
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
CA 02848664 2014-04-09
26
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.
CA 02848664 2014-04-09
27
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
CA 02848664 2014-04-09
28
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.
CA 02848664 2014-04-09
29
[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
CA 02848664 2014-04-09
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.
CA 02848664 2014-04-09
31
[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
CA 02848664 2014-04-09
32
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.
