Note: Descriptions are shown in the official language in which they were submitted.
METHODS AND SYSTEMS FOR RECYCLING RECOVERED GAS
FIELD OF INVENTION
The present invention relates generally to methods and systems for the
production of hydrocarbons
.. from a hydrocarbon reservoir. More specifically, the present invention
relates to methods and
systems involving the recycling of solvent-containing recovered gas.
BACKGROUND
Recovery of hydrocarbons from underground reservoirs is a complex and
demanding process,
particularly where hydrocarbons are to be recovered from oil sand deposits.
One approach for recovering hydrocarbons from oil sands involves an enhanced
oil recovery
(EOR) technology known as steam-assisted gravity drainage (SAGD).
Traditionally, SAGD is a
method whereby the oil sand deposit is contacted with one or more
injection/producer horizontal
well pairs, and steam is injected into the deposit via the injection well(s)
to heat and mobilize the
oil, causing it to drain into the producer well(s) located vertically below
the injection well(s), where
.. it can be produced to the surface. One subtype of the SAGD process adds
solvent in addition to
the steam, in a Solvent-Aided Process (SAP), whereby hydrocarbon solvent, such
as a low
molecular weight alkane or a natural gas liquid, is added to injected steam of
the SAGD operation.
Other solvent-utilizing processes have also been proposed including, for
example, VAPEX (an
example of which is described in U.S. Patent No. 5,899,274), Warm VAPEX (which
is VAPEX
using a heated diluting agent), Alternating Steam-Solvent Process, SAVEX (an
example of which
is described in U.S. Patent No. 6,662,872), SA-SAGD (an example of which is
described in
Canadian Patent No. 1,246,993 (Vogel)), and LASER (an example of which is
described in U.S.
Patent No. 6,708,759). Hydrocarbon solvent is generally used to improve
mobility in the
hydrocarbon reservoir, potentially improving production and/or reducing steam
and/or heating
requirements. However, the use of solvent can add significant expense due to
solvent costs; and,
if injected solvent is to be recovered and/or recycled, additional surface
processing apparatus may
be needed. A typical surface solvent recovery/recycling apparatus is described
in VAPEX, Warm
VAPEX and Hybrid VAPEX ¨ The State of Enhanced Oil Recovery for In Situ Heavy
Oils in
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Canada", James, L., A., Rezaei, N., Chatzis, I., JCPT, 2009, V. 47, No. 4.
SAGD operations typically result in the production of a casing gas that is
produced to the surface.
Likewise, SAGD operations typically produce a fluid emulsion to the surface
which contains
produced hydrocarbons along with entrained gas which is similar in composition
to the casing gas.
Casing gas produced from a hydrocarbon reservoir is usually piped from a
producer well head to
surface facilities for processing. Generally, casing gas contains small
molecule hydrocarbons
(mostly CH4) and quantities of CO2 and H2S. Managing and piping the H2S to
suitable processing
facilities can result in degradation or corrosion of piping due to the
corrosive nature of H2S. Typical
treatment of 1-12S is expensive and potentially hazardous, meaning that an
environmentally
regulated waste disposal scheme and rigorous equipment maintenance procedures
are involved.
Furthermore, produced casing gas often requires costly surface
processing/treatment apparatus
used to separate, treat, and/or recover casing gas components, in particular
recovered steam.
Canadian patent application no. 2,884,990. entitled Casing Gas Management
Method and System,
describes recently developed technology for the injection of casing gas into a
hydrocarbon
reservoir, and is herein incorporated by reference in its entirety.
A need exists for alternative, additional, and/or improved methods and/or
systems for producing
hydrocarbons and/or recycling recovered gas from an oil sands operation.
SUMMARY OF INVENTION
It has been found that a substantial portion of solvent injected dovvnhole as
part of a hydrocarbon
recovery operation may be produced back to the surface as a component of
recovered gas, which
may be re-injected back downhole, thereby recycling the solvent. Such methods
and systems may
reduce need for makeup solvent, and/or may reduce need for surface treatment
apparatus
traditionally used for gas treatment/separation and/or solvent recovery such
as, for example,
fractionation apparatus, flash separation, or compression and cooling.
Additionally, such methods
may also reduce the need for an expanded vapour recovery system.
In one embodiment of the present invention, there is provided a method for
producing
hydrocarbons from at least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
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driven, solvent-driven, or combined steam- and solvent-driven, on the
underground reservoir which includes:
injecting a solvent into the underground reservoir;
recovering a recovered gas from the underground reservoir, the recovered gas
comprising at least some of the injected solvent;
recycling the solvent by re-injecting the recovered gas into the same, or a
different, underground reservoir; and
producing hydrocarbons from at least one underground reservoir into which
the solvent and/or recovered gas is injected.
In a further embodiment of the method or methods outlined above, the step of
recovering comprises
producing the recovered gas to the surface in a produced gas stream, entrained
in a produced fluid
emulsion stream, or a combination thereof.
In a further embodiment of the present invention, there is provided a method
for producing
hydrocarbons from at least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
driven, solvent-driven, or combined steam- and solvent-driven operation on
the underground reservoir which includes:
injecting a solvent into the underground reservoir via an injection well
in communication with the underground reservoir;
recovering a recovered gas from the underground reservoir via a producer
well in communication with the underground reservoir, the recovered gas
comprising at least some of the injected solvent and being produced in a
produced gas stream, entrained in a produced fluid emulsion stream, or both;
recycling the solvent by:
optionally, mixing the solvent-containing recovered gas with steam,
solvent, gas, liquid or a combination thereof; and
re-injecting the recovered gas downhole via the same, or a different,
injection well to mobilize hydrocarbons in the underground reservoir
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with which said injection well communicates; and
producing hydrocarbons from at least one underground reservoir into which
the solvent and/or recovered gas is injected.
In a further embodiment of the present invention, there is provided a method
for producing
hydrocarbons from at least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
driven, solvent-driven, or combined steam- and solvent-driven operation on
the underground reservoir which includes:
injecting a solvent into the underground reservoir via an injection well
in communication with the underground reservoir;
recovering a fluid emulsion stream and a casing gas stream from the
underground reservoir via a producer well in communication with the
underground reservoir, the fluid emulsion stream being produced through a
production tubing string of the producer well and comprising produced
hydrocarbons, and the casing gas stream being produced through a casing
channel of the producer well and comprising a recovered gas comprising at
least some of the injected solvent;
recycling the solvent by:
optionally, mixing the solvent-containing recovered gas with steam,
solvent, gas, liquid or a combination thereof; and
re-injecting the recovered gas downhole via the same, or a different,
injection well to mobilize hydrocarbons in the underground reservoir
with which said injection well communicates; and
producing hydrocarbons from at least one underground reservoir into which
the solvent and/or recovered gas is injected.
In a further embodiment of the present invention, there is provided a method
for producing
hydrocarbons from at least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
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driven, solvent-driven, or combined steam- and solvent-driven operation on
the underground reservoir which includes:
injecting a solvent into the underground reservoir via an injection well
in communication with the underground reservoir;
recovering a fluid emulsion stream and a casing gas stream from the
underground reservoir via a producer well in communication with the
underground reservoir, the fluid emulsion stream being produced through a
production tubing string of the producer well and comprising produced
hydrocarbons, and the casing gas stream being produced through a casing
channel of the producer well, wherein the fluid emulsion stream and the
casing gas stream each comprise a recovered gas component comprising at
least some of the injected solvent;
recycling the solvent by:
collecting the recovered gas from the fluid emulsion stream, optionally
by heating the fluid emulsion stream, subjecting the fluid emulsion
stream to a pressure drop, or both;
combining the collected solvent-containing recovered gas from the fluid
emulsion stream with the solvent-containing recovered gas from the
casing gas stream;
optionally, mixing the recovered gas with steam, solvent, gas, liquid or
a combination thereof; and
re-injecting the recovered gas downhole via the same, or a different,
injection well to mobilize hydrocarbons in the underground reservoir
with which said injection well communicates; and
producing hydrocarbons from at least one underground reservoir into which the
solvent
and/or recovered gas is injected.
In a further embodiment of the present invention, there is provided a method
for producing
hydrocarbons from at least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
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CA 3014397 2018-08-17
driven, solvent-driven, or combined steam- and solvent-driven, operation on
the underground reservoir which includes:
injecting a solvent into the underground reservoir;
recovering a fluid emulsion stream from the underground reservoir, the fluid
emulsion stream comprising produced hydrocarbons and a recovered gas, the
recovered gas comprising at least some of the injected solvent and being
entrained in the fluid emulsion stream;
recycling the solvent by:
collecting the recovered gas from the fluid emulsion stream, optionally
by heating the fluid emulsion stream, subjecting the fluid emulsion
stream to a pressure drop, or both;
optionally, mixing the solvent-containing recovered gas with steam,
solvent, gas, liquid or a combination thereof; and
re-injecting the recovered gas into the same, or a different, underground
reservoir to mobilize hydrocarbons therein; and
producing hydrocarbons from at least one underground reservoir into which the
solvent
and/or recovered gas is injected.
In a further embodiment of the method or methods outlined above, the recovered
gas further
comprises one or more of steam, methane, CO2, or H2S recovered from the
underground reservoir,
and wherein the recovered gas is re-injected without being subjected to a gas
separation or
purification process.
In a further embodiment of the method or methods outlined above, the step of
mobilizing includes
performing a steam-assisted gravity drainage (SAGD), solvent-aided process
(SAP), vapour
extraction (VAPEX), warm VAPEX, heated-VAPEX (H-VAPEX), solvent driven process
(SDP),
alternating steam-solvent, liquid addition to steam for enhanced recovery
(LASER), solvent flood,
or cyclic solvent-dominated operation.
In a further embodiment of the method or methods outlined above, the recovered
gas is mixed with
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a slip-stream of steam taken from a steam line, and the resultant mixed stream
is re-introduced into
the main steam line for re-injection in the recycling step.
In a further embodiment of the method or methods outlined above, the recovered
gas is mixed with
steam via an eductor or a multi-phase pump for re-injection in the recycling
step.
In a further embodiment of the method or methods outlined above, the
recovering and recycling
steps are performed more than once.
In a further embodiment of the method or methods outlined above, the recovered
gas becomes
enriched with lighter hydrocarbons with each cycle of recovering and
recycling.
In a further embodiment of the method or methods outlined above, the recycling
step comprises
compressing the gas, heating the gas, or both, prior to re-injecting.
In a further embodiment of the method or methods outlined above, the
underground reservoir is
undergoing a reversible aquathermolysis reaction, and the step of recycling
drives the equilibrium
of the aquathermolysis reaction away from the production of H2S, decreasing
hydrogen sulfide
production, due to presence of H2S in the re-injected recovered gas.
In a further embodiment of the method or methods outlined above, the recovered
gas is used in the
recycling step substantially as-produced, and is not subjected to wellhead
separation or other
separation of gas components.
In a further embodiment of the method or methods outlined above, the
recovering and recycling
steps reduce or eliminate the use of make-up solvent in the mobilizing step.
In a further embodiment of the method or methods outlined above, the
recovering and recycling
steps reduce or eliminate need for the mobilizing step.
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In a further embodiment of the method or methods outlined above, the
recovering and recycling
steps reduce or eliminate gas surface processing and treatment requirements.
In a further embodiment of the method or methods outlined above, the recovered
gas is re-injected
in the recycling step via a second injection well located on a first well pad
which is shared with a
first injection well used for injecting the solvent in the step of mobilizing.
In a further embodiment of the method or methods outlined above, the recovered
gas is re-injected
in the recycling step via a second injection well located on a second well pad
which is distinct
from a first injection well used for injecting the solvent in the step of
mobilizing located on a first
well pad.
In a further embodiment of the method or methods outlined above, build-up of
non-condensable
gases is reduced by performing the step of recycling at the second injection
well located on the
second well pad which is distinct from the first injection well used in the
step of mobilizing located
on the first well pad.
In a further embodiment of the method or methods outlined above, the steps of
recovering and
recycling are performed more than once, and cascade from one distinct well or
well pad to the next
with each iteration.
In a further embodiment of the method or methods outlined above, the steps of
recovering and
recycling are performed more than once, and cascade from one distinct well or
well pad to the next
with each iteration, and wherein at least some re-injected recovered gas
migrates between wells or
well pads while underground.
In a further embodiment of the method or methods outlined above, the first and
second well pads
are comprised within the same pod.
In a further embodiment of the method or methods outlined above, the first
well pad is comprised
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within a first pod and the second well pad is comprised within a second pod.
In a further embodiment of the method or methods outlined above, the recovered
gas obtained in
the first pod is recycled to the second pod.
In a further embodiment of the method or methods outlined above, the step of
re-injecting the
recycled gas includes injection at least a portion of the recycled gas near or
at blowdovvn.
In a further embodiment of the present invention, there is provided a method
for producing
hydrocarbons from at least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
assisted gravity drainage (SAGD) operation on the underground reservoir
which includes:
injecting steam and a solvent into the underground reservoir via an
injection well in communication with the underground reservoir;
recovering a fluid emulsion stream and a casing gas stream from the
underground reservoir via a producer well in communication with the
underground reservoir, the fluid emulsion stream being produced through a
production tubing string of the producer well and comprising produced
hydrocarbons, and the casing gas stream being produced through a casing
channel of the producer well, wherein the fluid emulsion stream and the
casing gas stream each comprise a recovered gas component comprising at
least some of the injected solvent;
recycling the solvent by:
collecting the recovered gas from the fluid emulsion stream, casing gas
stream, or both;
mixing the recovered gas with steam to form a mixed stream comprising
steam and the solvent-rich recovered gas;
re-injecting the mixed stream downhole via the same, or a different, injection
well to mobilize hydrocarbons in the underground reservoir with which said
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injection well communicates; and
optionally, producing hydrocarbons from the underground reservoir into
which the mixed stream is injected.
In a further embodiment of the method or methods outlined above, the mixed
stream is generated
by mixing the recovered gas with a slip-stream of steam taken from a main SAGD
steam line, and
the resultant mixed stream is re-introduced into the main SAGD steam line for
re-injection via one
or more injection wells in communication with the main SADG steam line.
In a further embodiment of the method or methods outlined above, the casing
gas stream is mixed
with steam via an eductor or a multi-phase pump.
In a further embodiment of the method or methods outlined above, the
recovering and recycling
steps are performed more than once.
In a further embodiment of the method or methods outlined above, the recovered
gas becomes
enriched with lighter hydrocarbons with each cycle of recovering and
recycling.
In a further embodiment of the method or methods outlined above, the collected
recovered gas is
compressed, heated, or both, prior to re-injection.
In a further embodiment of the method or methods outlined above, the recovered
gas comprises a
steam component and a gas component, the gas component comprising the solvent,
methane, H2S,
and CO2.
In a further embodiment of the method or methods outlined above, the
underground reservoir is
undergoing a reversible aquathermolysis reaction, and the re-injecting drives
the equilibrium of
the aquathermolysis reaction away from the production of I-IS, decreasing
hydrogen sulfide
production.
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In a further embodiment of the method or methods outlined above, the casing
gas stream produced
through the casing gas channel is used substantially as produced and is not
subjected to wellhead
separation.
In a further embodiment of the method or methods outlined above, the
recovering and recycling
steps reduce or eliminate the use of make-up solvent in the mobilizing step.
In a further embodiment of the method or methods outlined above, the
recovering and recycling
steps reduce or eliminate casing gas surface processing and treatment
requirements.
In a further embodiment of the method or methods outlined above, the injection
well of the
recycling step is the same injection well used in the step of mobilizing.
In a further embodiment of the method or methods outlined above, the injection
well of the
recycling step is a different injection well located on a first well pad which
is shared with the
injection well used in the step of mobilizing.
In a further embodiment of the method or methods outlined above, the injection
well of the
recycling step is a different injection well located on a second well pad,
which is distinct from the
injection well used in the step of mobilizing located on a first well pad.
In a further embodiment of the method or methods outlined above, build-up of
non-condensable
gases is reduced by performing the step of recycling at the different
injection well located on the
second well pad which is distinct from the injection well used in the step of
mobilizing located on
the first well pad.
In a further embodiment of the method or methods outlined above, the first and
second well pads
are comprised within the same pod.
In a further embodiment of the method or methods outlined above, the first
well pad is comprised
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within a first pod and the second well pad is comprised within a second pod.
In a further embodiment of the method or methods outlined above, the recovered
gas obtained in
the first pod is recycled to the second pod.
In a further embodiment of the method or methods outlined above, the steps of
recovering and
recycling are performed more than once, and cascade from one distinct well or
well pad to the next
with each iteration.
In a further embodiment of the method or methods outlined above, the steps of
recovering and
recycling arc performed more than once, and cascade from one distinct well or
well pad to the next
with each iteration, and wherein at least some re-injected recovered gas
migrates between wells or
well pads while underground.
In a further embodiment of the method or methods outlined above, the solvent
comprises
condensate, butane, propane, or any combination thereof.
In a further embodiment of the method or methods outlined above, the recovered
gas re-injected
at the recycling step is re-injected at an increased pressure, thereby causing
at least some of the
recovered gas to migrate to at least one other well located on the same well
pad, or at least one
other well located on a communicating well pad.
In a further embodiment of the method or methods outlined above, the step of
re-injecting the
recycled gas includes injection at least a portion of the recycled gas as
blowdown.
In a further embodiment of the present invention, there is provided a system
for producing
hydrocarbons from an underground reservoir, said system comprising:
a solvent source;
at least one well pad having a producer well in communication with the
underground reservoir;
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at least one collector for obtaining solvent-rich recovered gas from the
producer well; and
one or more injection lines in communication with the underground reservoir
for injecting solvent from the solvent source, re-injecting the solvent-rich
recovered gas from the collector, or a combination thereof, into the
underground reservoir.
In a further embodiment of the present invention, there is provided a system
for producing
hydrocarbons from an underground reservoir, said system comprising:
a solvent source;
at least one well pad having a producer well in communication with the
underground reservoir;
at least one mixer for mixing solvent-rich recovered gas from the producer
well with steam, solvent, gas, or a combination thereof, to provide a mixed
stream; and
one or more injection lines in communication with the underground reservoir
for injecting solvent from the solvent source, the mixed stream from the
mixer, or a combination thereof, into the underground reservoir.
In a further embodiment of the present invention, there is provided a system
for producing
hydrocarbons from an underground reservoir, said system comprising:
a high pressure steam source;
a solvent source;
at least one well pad having a producer well in communication with the
underground reservoir;
at least one mixer for mixing solvent-rich recovered gas from the producer
well with steam from the high pressure steam source to provide a mixed
stream; and
one or more injection lines in communication with the underground reservoir
for injecting solvent from the solvent source, steam from the high pressure
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steam source, the mixed stream from the mixer, or any combination thereof,
into the underground reservoir.
In a further embodiment of the present invention, there is provided a system
for producing
hydrocarbons from an underground reservoir, said system comprising:
a high pressure steam source;
a solvent source;
a producer well in communication with the underground reservoir, the
producer well comprising a casing, a production tubing string inside the
casing for producing a fluid emulsion stream comprising produced
hydrocarbons to the surface, and a casing channel formed between the casing
and the production tubing string for producing a casing gas to the surface,
the
casing gas comprising a solvent-rich recovered gas;
a mixer for mixing solvent-rich recovered gas from the casing channel with
steam from the high pressure steam source to provide a mixed stream; and
an injection line for injecting the mixed stream into the underground
reservoir.
In a further embodiment of the system or systems outlined above, the system is
for use in
performing a method according to any one of those disclosed above.
In a further embodiment of the system or systems outlined above, the mixer
comprises a first inlet
which receives steam from a slip-stream of steam taken from an upstream region
of the high
pressure steam source, a second inlet which receives the solvent-rich
recovered gas, a mixing
region which mixes the steam and the solvent-rich recovered gas to provide the
mixed stream, and
a mixed stream outlet for introducing the mixed stream into a downstream
region of the high
pressure steam source prior to reaching the injection line.
In a further embodiment of the system or systems outlined above, the mixer
comprises an eductor
having first inlet which is a motive fluid inlet, and a second inlet which is
a suction fluid inlet.
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In a further embodiment of the system or systems outlined above, the mixer
comprises a multiphase
pump or multiphase compressor.
In a further embodiment of the system or systems outlined above, the system
further comprises a
casing gas cooler upstream of the multiphase pump or multiphase compressor.
In a further embodiment of the system or systems outlined above, the system
further comprises a
low pressure group separator, pressure drop separator, heating separator, or
any combination
thereof, for obtaining the solvent-rich recovered gas from a fluid emulsion
stream produced from
the producer well.
In a further embodiment of the system or systems outlined above, the system
further comprises a
dehydrator.
In a further embodiment of the system or systems outlined above, the system
further comprises a
3 phase separator for obtaining solvent from the recovered gas.
In a further embodiment of the system or systems outlined above, the system
further comprises a
compressor, heater, or both, for compressing and/or heating the recovered gas
prior to injection.
In a further embodiment of the system or systems outlined above, the recovered
gas is used
substantially as produced, and the system is free of wellhead separation
apparatus.
In a further embodiment of the system or systems outlined above, the system is
modular, and one
or more components can be moved between injection and producer well pairs
and/or between well
pads.
In a further embodiment of the system or systems outlined above, the injection
line and the
producer well are part of a SAGD well pair.
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In a further embodiment of the system or systems outlined above, the injection
line and the
producer well are located on the same well pad.
In a further embodiment of the system or systems outlined above, the injection
line and the
producer well are located on different well pads.
BRIEF DESCRIPTION OF DRAWINGS
These, and other features and aspects, of the present invention will become
better understood with
regard to the following description and accompanying Figures, wherein:
FIGURE 1 shows a schematic drawing of an embodiment of a hydrocarbon
production operation,
in this example employing a SAGD well pair, which may be modified for
performing a
hydrocarbon production method as described herein;
FIGURE 2 shows a schematic drawing of an embodiment of a hydrocarbon
production system
which is configured for performing a hydrocarbon production method as
described herein;
FIGURE 3 is a schematic drawing of another embodiment of a hydrocarbon
production system
which is configured for performing a hydrocarbon production method as
described herein;
FIGURES 4-14 show schematic drawings of a plurality of hydrocarbon production
system
embodiments having various configurations for performing hydrocarbon
production methods as
described herein which may utilize recovered gas cascading;
FIGURE 15 shows Half Rate Oil Production reservoir simulation results for
SAGD, a SAP, and a
SAP with Methane Injection Runs;
FIGURE 16 shows CSOR for reservoir simulation results for SAGD, a SAP, and a
SAP with
Methane Injection Runs;
FIGURE 17 shows a schematic drawing of an embodiment of a three pad Cascading
system;
FIGURE 18 shows a CSOR comparison between SAGD, a SAP with propane, and a SAP
with
propane and with methane co-injection;
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FIGURE 19 shows an oil rate comparison between SAGD, a SAP with propane, and a
SAP with
propane and with methane co-injection;
FIGURE 20 shows a SAP weight % effect on uplift with CSOR;
FIGURE 21 provides an Alkane Bubble Point Curve;
FIGURE 22 is a schematic drawing of an embodiment of a hydrocarbon production
system which
is configured for performing a gas lift hydrocarbon production method as
described herein;
FIGURE 23 is a schematic drawing of an embodiment of a hydrocarbon production
system which
is configured for performing a hydrocarbon production method as described
herein incorporating
an educator for mixing the solvent-containing recovered gas with steam;
FIGURE 24 shows a schematic drawing of an embodiment of a hydrocarbon
production system
which is configured for performing a hydrocarbon production method as
described herein
incorporating a compressor system;
FIGURE 25 is a schematic drawing of an embodiment of a hydrocarbon production
system which
is configured for performing an ESP hydrocarbon production method as described
herein;
FIGURE 26 is a schematic drawing of an embodiment of a hydrocarbon production
system which
is configured for performing a hydrocarbon production method incorporating a
positive
displacement rod pump as described herein; and
FIGURE 27 shows a schematic drawing of an embodiment of a hydrocarbon
production system
comprising a basic solvent Cascade design as described herein.
DETAILED DESCRIPTION
Described herein are methods and systems for producing hydrocarbons and/or
managing recovered
gas from hydrocarbon recovery operation such as an oil sands operation. It
will be appreciated that
embodiments and examples are provided for illustrative purposes intended for
those skilled in the
art, and are not meant to be limiting in any way.
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While performing a solvent-assisted SAGD oil recovery process involving the
injection of solvent
with steam, it was recognized that a substantial portion of the solvent
injected was produced back
to surface with the casing gas through the casing gas line. For example, in a
typical SAGD
operation where 15 wt% solvent is injected with the steam, between about 50-
70% of the solvent
injected is recovered, the remainder staying in the reservoir. It is believed
that the solvent produced
may represent a significant component of recovered gas. In one embodiment,
solvent represents
greater than 50wt% of the casing gas produced. Particularly where lighter
solvents, such as
propane or butane, are used, the majority of the produced solvent may be
recovered with the casing
gas, rather than with the produced fluid emulsion. An illustrative example of
typical amounts of
produced solvent, in this case butane (relative to methane) that has been
found in the casing gas is
shown in Table 1. In this instance, butane was injected on average between 1-
20 wt %. As per
Table 1, of the casing gas produced, the vast majority was produced butane (-
95%). It is expected
that the in the case of a propane SAP process, the percentage of solvent
produced through the
casing may be even higher due to the higher volatility of propane as compared
to butane.
As can be seen from Table 1, over 90% of the (dry) casing gas was made up of
solvent.
Furthermore, the vast majority (8.8 of 9.3 tonnes) of the produced butane was
in the casing gas.
Table 1: Butane and Methane Production for a Butane SAP pilot
Date Cl in Casing Gas C4 in Casing Gas Casing Produced C4 Total
Produced C4
tonnes tonnes tonnes
2016-10-14 0.13 1.7 81 2.1
2016-11-05 0.45 4.2 86 4.9
2016-11-08 14.1 14.6
2016-11-09 15.3 15.8
2016-11-12 8.5 9.0
2016-11-12 6.7 7.3
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2016-11-17 0.61 2.2 65 3.4
2016-11-20 8.3 8.4
2016-11-25 9.5 9.7
2016-11-28 1.95 10.2 98 10.4
2016-11 average 8.8 95 9.3
Figure 1 shows a schematic drawing of an embodiment of a hydrocarbon
production operation
employing a SAGD well pair, in which a solvent is injected along with the
steam, and from which
a solvent-containing recovered gas may be obtained similarly to the studies
described above. Such
an operation may be adapted for performing methods as described herein, as
further detailed below.
As well, based on these observations, it is believed that the above effects
may also apply to other
hydrocarbon recovery operations implementing solvent injection, and are not
limited to SAGD.
By way of example, in certain embodiments, solvent may be recovered from a
primarily steam-
driven operation, a primarily solvent-driven operation, a combined steam- and
solvent-driven
operation, or a gas-lift operation including injection of solvent. In certain
embodiments, the
hydrocarbon recovery operation may include steam-assisted gravity drainage
(SAGD); a solvent-
only recovery process without steam; a solvent-aided process (SAP); vapour
extraction (VAPEX);
warm VAPEX; heated-VAPEX (H-VAPEX); alternating steam-solvent; liquid addition
to steam
for enhanced recovery (LASER); solvent flood; or cyclic solvent-dominated
operation.
.. Accordingly, Figure 2 provides a schematic drawing of an embodiment of a
system for performing
a hydrocarbon recovery method as described herein. In the depicted embodiment,
a first well is
provided in communication with an underground reservoir. The well is supplied
with solvent from
a solvent storage unit, and is used to inject the solvent downhole. A
hydrocarbon-containing fluid
emulsion, and a recovered gas, are produced from the reservoir, both
containing recovered gas
which contains at least some of the injected solvent. Although Figure 2
depicts the hydrocarbon-
containing fluid emulsion and the recovered gas as being produced to the
surface through the same
well used to inject the solvent, it will be understood various other
configurations may be possible,
19
CA 3014397 2018-08-17
and that the injection of solvent and production of the fluid emulsion and/or
recovered gas do not
need to be conducted through the same well. The produced fluid emulsion is
directed to a separator
which separates recovered gas from the produced hydrocarbons. The recovered
gas from the
separator is directed to a recovered gas storage unit, where it is mixed with
recovered gas received
from the well. The recovered gas may be compressed and/or heated in the
recovered gas storage
unit. The recovered gas from the recovered gas storage unit is then supplied
back to the well and/or
to a new well located at the same, or a different, well pad for re-injection
back downhole, thereby
recycling the solvent and/or reducing the need for surface processing of
casing gas, produced gas,
and/or the fluid emulsion stream.
As will be understood, in a solvent aided process, or a solvent only process,
for example, solvent
may be recovered from the produced fluid emulsion. The produced fluid emulsion
may flow
through a separator at the well pad, wherein entrained recovered gas may be
recovered from the
fluid emulsion through a gas line. Such recovered gas recovery may occur as a
result of a pressure
drop in the separator to flash off additional gas, including solvent, methane,
and possibly H2S
and/or CO2. Other separation methods may be used, including but not limited to
separation by
heating. In further embodiments, in the case of a gas lift system, the
recovered gas may be produced
with the fluid emulsion through the producer well. In such a system, the
entrained recovered gas
within the emulsion may be produced to surface and separated using a suitable
separator known to
the person of skill in the art having regard to the teachings herein.
By way of example, in an embodiment employing a solvent-aided process, or a
solvent only
process, produced fluid emulsion may be flashed to obtain further solvent
and/or recovered gas
therefrom.
In order to avoid implementing standard (and potentially costly) solvent
recovery/recycling
apparatus to treat the produced recovered gas, methods and systems for re-
injecting produced
solvent-rich recovered gas are provided herein as an alternative solvent
recycling technology as
described in detail hereinbelow.
In an embodiment, there is provided herein a method for producing hydrocarbons
from at least one
underground reservoir, said method comprising:
CA 3014397 2018-08-17
mobilizing hydrocarbons in the underground reservoir by performing a steam-
driven,
solvent-driven, or combined steam- and solvent-driven, operation on the
underground
reservoir which includes:
injecting a solvent into the underground reservoir;
recovering a recovered gas from the underground reservoir, the recovered gas
comprising
at least some of the injected solvent;
recycling the solvent by re-injecting the recovered gas into the same, or a
different,
underground reservoir; and
producing hydrocarbons from at least one underground reservoir into which the
solvent
and/or recovered gas is injected.
As will be understood, a steam-driven operation may include any suitable
hydrocarbon production
operation known in the field which is primarily driven by steam injection into
the reservoir. Steam-
driven operations may be those using only steam, and those using mainly steam
for mobilization,
for example greater that 50 wt% steam. Steam-driven operations may include,
for example, steam-
assisted gravity drainage (SAGD); SA-SAGD; solvent aided processes (SAP)
utilizing less than
50 wt% solvent, and/or ES-SAGD (as described in CA 2,323,029). Steam-driven
processes may,
in certain embodiments, employ a diluting agent, for example a solvent, in
combination with
steam. In certain embodiments, steam-driven operations may employ between
about 0% to about
50 wt% solvent, or any sub-range therein, or any value therebetween.
As well, a solvent-driven operation may include those which are solvent
dominant having greater
than 50 wt% solvent, where solvent is generally the primary driver used to
reduce the viscosity of
the viscous hydrocarbons. Solvent-driven operations may include any suitable
hydrocarbon
production operation known in the field which is primarily driven by injection
of solvent into the
reservoir. Solvent-driven operations may be those using only solvent, and
those using mainly
solvent for mobilization. Solvent-driven operations may include, for example,
VAPEX, and heated
VAPEX. In certain embodiments, solvent-driven operations may employ between
about 50% to
about 100 wt% solvent, or any sub-range therein, or any value therebetween.
21
CA 3014397 2018-08-17
Combined steam- and solvent-driven operations may include any suitable
hydrocarbon production
operation known in the field which is driven by injection of both steam and
solvent (either
separately or combined via co-injection) into the reservoir. Steam- and
solvent-driven operations
may be those using, at least to some extent, both steam and solvent for
mobilization, and may
encompass the steam-driven operations and solvent-driven operations described
above which use
some combination of steam and solvent for mobilization. Steam- and solvent-
driven operations
may include, for example, a solvent-aided process (SAP) where the wt% of
solvent varies (see, for
example, CA 2,553,297) and SAVEX.
As will be understood, solvent containing recovered gas may be produced back
to surface in a
produced gas stream, entrained in a fluid emulsion stream, or both. Recovered
gas may be
produced to the surface via a producer well (for example, via a recovered gas
line within the
, producer well). Recovered gas may be in a produced gas stream, or entrained
in a fluid emulsion,
produced to surface with a pump, or via an artificial lift system, for
example. Gas lift is a method
of artificial lift that uses a source of high-pressure gas to lift the well
fluids. This gas source, in
one embodiment, may be external and may supplement formation gas.
By way of example, in certain embodiments, solvent may be recovered from a
primarily steam-
driven operation, a primarily solvent-driven operation, or a combined steam-
and solvent-driven
operation, which may, or may not, use gas-lift. In certain embodiments, the
hydrocarbon recovery
operation may include steam-assisted gravity drainage (SAGD); a solvent-only
recovery process
without steam; a solvent-aided process (SAP); vapour extraction (VAPEX); warm
VAPEX;
heated-VAPEX (H-VAPEX); solvent driven process (SDP), alternating steam-
solvent; liquid
addition to steam for enhanced recovery (LASER); solvent flood; or cyclic
solvent-dominated
operation.
As will be understood, methods described herein do not require all involved
wells/well pads to
.. operate under the same hydrocarbon mobilization technique. For example,
some well pads may be
operated under a SAP process, while another may be operated as a solvent
driven well, and
recovered gas from these wells may be used to drive, for example, another SAP
process pad. As
will be understood, various configurations and combinations may be used
depending on the
particular application. In one example, an solvent only recovery process pad
may be used to feed
22
CA 3014397 2018-08-17
one or more SAP process pads.
Steam-assisted gravity drainage (SAGD) operations may include any suitable
SAGD operation
known in the art involving one or more injection/producer horizontal well
pairs, through which
steam may be injected into the deposit via the injection well(s) to heat and
mobilize the oil, causing
it to drain into or otherwise collect at the producer well(s), where it can be
produced to the surface.
Solvent-aided processes (also referred to as solvent-assisted processes; SAP)
may include any
suitable SAP process in which hydrocarbon solvent, such as a low molecular
weight alkane (for
example, C1-C7 alkanes) or a natural gas liquid, is added to injected steam of
the SAGD operation
improve mobility in the hydrocarbon reservoir. As will be understood, solvent
processes as
described herein may also include, in certain embodiments, Liquid Addition to
Steam for
Enhanced Recovery (LASER), or another process where solvent is injected such
as, but not limited
to, solvent flood. In certain embodiments, solvent processes may include
solvent driven processes
(SDP). vapour extraction (VAPEX), heated-VAPEX (H-VAPEX), or cyclic solvent
dominated
processes.
As will be understood, produced or recovered hydrocarbons may include any oil
and gas
components typically recovered from oil sands. Hydrocarbons may be produced
from the
underground reservoir at any suitable stage during the above method. For
example, hydrocarbons
may be produced from the hydrocarbon reservoir during any or all of the steps
of the methods
described herein. It will be recognized that hydrocarbons may typically be
produced from the
hydrocarbon reservoir via a producer well in communication therewith during or
after any one or
more of the method steps. Hydrocarbons may, for example, be produced during or
after the
mobilizing step; before, during, or after the recovering step; before, during,
or after the recycling
step; or any suitable combination thereof.
In certain embodiments, the solvent injected during the step of mobilizing may
comprise, for
example, a hydrocarbon-based solvent. In one embodiment, the solvent may be a
hydrocarbon
solvent comprising low molecular weight alkane (for example, C -C7 alkanes) or
a natural gas
liquid. In certain embodiments, the solvent may comprise condensate, butane,
propane, pentane
or any combination thereof In certain embodiments, hydrocarbon solvents may
include a mixture
of at least two or more hydrocarbon compounds having a number of carbon atoms
from the range
23
CA 3014397 2018-08-17
of CI to C30+, or any individual hydrocarbon or combination of hydrocarbons
therein. An example
of a hydrocarbon mixture may be referred to as condensate. Condensates often
comprise
hydrocarbons in the range of C3 to C12 or higher. Generally light end
compounds are those
hydrocarbons of such a mixture having the lowest number of carbon atoms,
typically CI to C7, but
possibly higher in some cases. Such light end compounds have the lowest
molecular weights, and
are generally the more volatile of the hydrocarbon compounds of the mixture.
In certain embodiments, the solvent may further comprise one or more additives
such as, for
example, CO2, a surfactant, or another non-reacting molecule for enhancing oil
mobility. In certain
embodiments, the solvent may comprise a surfactant additive in low amounts,
such as in the ppm
range, and the surfactant concentration may build up over time with repeated
iterations of recovery
and recycling.
As will be understood, a recovered gas may be recovered from the underground
reservoir during
or subsequent to the mobilizing step. The recovered gas will typically be
recovered from a producer
well in communication with the underground reservoir, however the skilled
person having regard
to the teachings herein will be aware of other means for recovering the
recovered gas suitable for
the particular implementation. The recovered gas may include any gas recovered
from the
underground reservoir which contains at least some of the injected solvent. By
way of example,
the recovered gas may include produced gas, casing gas, gas entrained in a
produced fluid
emulsion, or any combination thereof, which contains at least some of the
injected solvent. Since
the recovered gas is obtained from the underground reservoir, the recovered
gas will typically
comprise, in addition to at least some of the injected solvent, one or more of
steam, methane, CO2,
or 112S from the underground reservoir. In certain embodiments, the recovered
gas may be
produced to the surface in a produced gas stream, entrained in a produced
fluid emulsion stream,
or both.
In certain embodiments, recycling of the injected solvent may be performed by
re-injecting the
recovered gas into the same, or a different, injection site or underground
reservoir. Since the
recovered gas contains at least some solvent previously injected downhole, re-
injection of the
recovered gas may reduce or eliminate the use of make-up solvent in the
mobilizing step, reduce
or eliminate need for the mobilizing step, and/or reduce or eliminate gas
surface processing and
24
CA 3014397 2018-08-17
treatment requirements. In certain embodiments, recovered gas from a plurality
of wells may be
obtained and combined.
In certain embodiments, at least a portion of the recovered gas may be
directed to a central plant
(i.e. may not be recycled) via a "bleed line". In certain embodiments, the
bleed volume may be
negligible with respect to the plant operations. In other embodiments, the
bleed volume may
require further processing at the central plant so it does not adversely
affect the plant operation.
This additional processing may include separation, flashing, fractionation,
compression with
cooling, dehydration, Joule-Thompson cooling or any combination of such
processes.
In certain embodiments, where a cascade system is implemented, there may be an
abundance of
propane or other light hydrocarbon remaining where the last pad does not
cascade into a blowdown
operation. In such circumstances, a processing facility may be implemented,
optionally nearby, to
suitably deal with this abundance of propane or other light hydrocarbon.
Methods as described hereinabove may be tailored to suit a particular desired
application, or as
needed based on specific conditions. Embodiments of methods falling within
those described
hereinabove and tailored for particular applications are described below.
In an embodiment, there is provided herein a method for producing hydrocarbons
from at least one
underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
driven,
solvent-driven, or combined steam- and solvent-driven operation on the
underground
reservoir which includes:
injecting a solvent into the underground reservoir via an injection well in
communication with the underground reservoir;
recovering a recovered gas from the underground reservoir via a producer well
in
communication with the underground reservoir, the recovered gas comprising at
least some
of the injected solvent and being produced in a produced gas stream, entrained
in a
produced fluid emulsion stream, or both;
CA 3014397 2018-08-17
recycling the solvent by:
optionally, mixing the solvent-containing recovered gas with steam, solvent,
gas,
liquid or a combination thereof; and
re-injecting the recovered gas downhole via the same, or a different,
injection well
to mobilize hydrocarbons in the underground reservoir with which said
injection
well communicates; and
producing hydrocarbons from at least one underground reservoir into which the
solvent
and/or recovered gas is injected.
As will be understood, in such an embodiment, an injection well in
communication with the
underground reservoir may be used for injecting the solvent into the
underground reservoir, and a
producer well in communication with the underground reservoir may be used for
recovering the
recovered gas from the underground reservoir. Recovered gas may be produced as
a gas stream,
entrained in a fluid emulsion stream which also comprises produced
hydrocarbons, or a
combination thereof. Recovered gas may, optionally, be mixed with additional
steam, solvent, gas,
liquid or a combination thereof, and may be re-injected back downhole via the
same, or a different,
injection well so as to mobilize hydrocarbons in the reservoir and facilitate
hydrocarbon
production.
It will be recognized that, where mixing of the solvent-containing recovered
gas with steam is to
be performed, the mixing may be achieved using any suitable apparatus known in
the art. For
example, mixing may be performed with an eductor (see Canadian patent
application publication
no. 2,884,990, herein incorporated by reference), a compressor, a pump (such
as, but not limited
to, a screw pump), or a multiphase pump. An educator may be used with steam as
the motive to
draw in casing gas to the injection points as shown in Figure 23.
It will be recognized that, where further separation of solvent from the
solvent-containing
recovered gas is desired, a cooling and compression system may be used for
separation of a
recovered gas stream. The cooling and compression system may comprise a heat
exchanger, a
cooling unit (such as an aerial cooler), or a combination thereof. In certain
embodiments, the
26
CA 3014397 2018-08-17
recovered gas stream from a first pad enters a cooler where the temperature of
the gas stream is
decreased. The water entrained in the gas then preferentially condenses and
may return to the
central facility. The treated gas stream is compressed and cooled. The
previously injected solvent,
for example butane or propane, preferentially condenses and exits through a
separator, then
optionally, mixes with steam and/or make-up solvent, and is reinjected into a
second pad (see
Figure 24).
In the context of the present disclosure, this method, and other such methods
of cooling and
compressing solvent from a solvent-containing recovered gas, may be initiated
based on a
condition-set trigger. The condition-set trigger may be a concentration
trigger. For example,
cooling and compressing may be initiated when the solvent component of a
casing gas stream
reaches a certain mol % within the casing gas stream, for example in certain
embodiments when
the solvent accounts for greater than about 90 mol% of the casing gas stream
on a dry basis. The
condition-set trigger may alternatively be a flow-rate trigger. For example,
in certain embodiments,
cooling and condensing may be initiated when the solvent component of the
casing gas flow is
greater than a pre-set condition such as between about 1 and 5 tonnes / day
(in particular at about
3 tonnes /day). It will be recognized that, where separation of solvent from
the solvent-containing
recovered gas stream is desired, a group separator, a distillation unit, an
absorption processes unit,
an adsorption process unit, a membrane separation unit, a filtration unit, or
a combination thereof
may be used.
In certain embodiments, a solvent-containing recovered gas stream may be split
into one or more
streams. For example, in an embodiment where solvent recycling is employed on
a single well, a
solvent-containing recovered gas stream may be split into a first stream that
is re-injected into the
well without additional treatment, and a second stream that is not. The second
stream may, for
example, be a slip stream. The provision of the second stream may reduce the
extent of methane
build up within the reservoir, and the mol% ratio of the first stream to the
second stream may be
manipulated to balance production rates, conditioning requirements, and make-
up solvent
requirements against methane build up. For example, where production from the
reservoir with
repeated solvent recycling results in a methane concentration that is
increasing over time, the ratio
of the first stream to the second stream may be decreased to bleed off methane
via the second
27
CA 3014397 2018-08-17
stream. Likewise, the ratio of the first stream to the second stream may be
increased when methane
build up within the reservoir is not negatively impacting production (so as to
reduce make-up
solvent requirements and/or treatment requirements). In certain embodiments,
the ratio of the first
stream to the second stream may be less than about 95:5 mol% on a dry basis.
In particular, the
ratio of the first stream to the second stream may be less than about 90:10
mol% on a dry basis
(optionally less than about 80:20, 70:30, 60:40, or 50: 50 mol% on a dry
basis). Those skilled in
the art, having the benefit of the present disclosure, will be able to select
a suitable ratio of the first
stream to the second stream in order to balance production rates, conditioning
requirements, and
make-up solvent requirements against methane build up. As discussed herein,
the second stream
may be re-injected after being treated to reduce the concentration of methane.
Those skilled in the
art, having the benefit of the present application, will be able to account
for relevant conditioning
requirements when treating the second stream for re-injection and will be able
to adjust their
methods accordingly. The second stream may alternatively be injected into an
alternate well,
directed to a central processing facility, or otherwise handled. The
conditioning of the second
stream may comprise heating, cooling, compressing, depressurizing, mixing with
an alternate
stream, or a combination thereof.
Methods that involve separating a solvent-containing recovered gas stream into
one or more
streams may be initiated based on a condition-set trigger. The condition-set
trigger may be a flow-
rate trigger. For example, a solvent-containing casing gas stream may be
separated into a first
stream and a second stream if the solvent-containing casing gas stream has a
methane flow rate
that is greater than about 3 tonnes / day. The condition-set trigger may
alternatively be a
concentration trigger. For example, a solvent-containing casing gas stream may
be separated into
a first stream and a second stream if methane accounts for more than about 25
mol% of the solvent-
containing casing gas stream on a dry basis.
In certain embodiments, the recovered gas may be primed for re-injection. For
example, the
recovered gas may be heated and/or compressed prior to re-injection. It will
be recognized that
conditioning a recovered gas for re-injection may involve heating by one or
more of a variety of
methods. For example, a recovered gas may be heated, prior to injection, by
heat exchange with
another stream such as a produced fluid emulsion stream, a produced casing gas
stream, a steam
28
CA 3014397 2018-08-17
stream, or a combination thereof Likewise, a recovered gas stream may be
heated, prior to
injection, by a direct heater such as a fuel-fired heater, an electric heater,
an
electromagnetic/induction heater, or a combination thereof. Moreover, a
recovered gas stream may
be heated, prior to injection, by mixing with an alternate stream that has a
higher temperature than
the recovered gas stream (such as a steam stream, a makeup solvent stream, or
a combination
thereof). In certain embodiments, conditioning the recovered gas for re-
injection may be initiated
when the casing gas stream, the production stream, or a combination thereof
falls below a set
temperature. For example, heating may be initiated when the temperature of the
casing gas stream
falls below about 150 C (in particular below about 175 C). In certain
embodiments, such a method
may be employed to provide the recovered gas substantially in the vapour phase
for re-injection
(optionally as part of a warm VAPEX operation). In another embodiment, there
is provided herein
a method for producing hydrocarbons from at least one underground reservoir,
said method
comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
driven,
solvent-driven, or combined steam- and solvent-driven operation on the
underground
reservoir which includes:
injecting a solvent into the underground reservoir via an injection well in
communication with the underground reservoir;
recovering a fluid emulsion stream and a casing gas stream from the
underground reservoir
via a producer well in communication with the underground reservoir, the fluid
emulsion
stream being produced through a production tubing string of the producer well
and
comprising produced hydrocarbons, and the casing gas stream being produced
through a
casing channel of the producer well and comprising a recovered gas comprising
at least
some of the injected solvent;
recycling the solvent by:
optionally, mixing the solvent-containing recovered gas with steam, solvent,
gas,
liquid or a combination thereof; and
29
CA 3014397 2018-08-17
re-injecting the recovered gas downhole via the same, or a different,
injection well
to mobilize hydrocarbons in the underground reservoir with which said
injection
well communicates; and
producing hydrocarbons from at least one underground reservoir into which the
solvent
and/or recovered gas is injected.
As will be understood, where a producer well (such as a typical SAGD producer
well, for example)
is used, the producer well may comprise an inner production tubing string
through which the fluid
emulsion may be transferred to the surface. It will be understood that the
inner production tubing
string may have alternative configurations, and may include any suitable
passage or channel
.. formed in the producer well through which the fluid emulsion stream may be
produced to the
surface. A casing gas stream, which may contain solvent-rich recovered gas
including previously-
injected solvent and (optionally) previously-injected steam (if used), may
also be produced to the
surface through a producer well. As will be understood, the producer well may
further comprise
an outer casing, and a casing channel formed between the outer casing and the
inner production
.. tubing string, through which the casing gas stream may be transferred to
the surface. In certain
embodiments, the casing channel may be an annular channel formed between the
outer casing and
the inner production tubing string. It will be understood that the casing
channel may have
alternative configurations, and may include any suitable passage or channel
formed in the producer
well through which the casing gas stream may be produced to the surface
separately, or at least
.. substantially separately, from the fluid emulsion stream. As will be
understood, in certain
embodiments the fluid emulsion stream and the casing gas stream are produced
to the surface
separately from one another, thereby reducing or removing need for surface
separation/treatment
events to separate out the produced casing gas in certain examples.
In certain embodiments, a downhole electric submersible pump (ESP) in
communication with the
producer well may be used to separately deliver the fluid emulsion stream and
the casing gas
stream to the surface (Figure 25). As will be understood, other technologies
may be used to
produce the emulsion to surface, for example gas lift (Figure 22) or other
artificial lift systems
(such as positive displacement rod pump as shown in Figure 26) may be used to
deliver the fluid
emulsion stream and gas stream to surface. Typically, where a casing gas
stream is produced, this
CA 3014397 2018-08-17
stream flows up the casing channel without assistance.
In traditional SAGD operations, separately produced fluid emulsion casing gas
streams are sent to
a facility for further processing. Casing gas produced from a hydrocarbon
reservoir has
traditionally been piped from a producer well head to surface facilities for
processing. Generally,
casing gas contains small molecule hydrocarbons (mostly CH4) and quantities of
CO2 and H2S.
Managing and piping the H2S to suitable processing facilities can result in
the degradation or
corrosion of the piping due to the corrosive nature of H2S. Typical treatment
of H2S is expensive
and potentially hazardous, meaning that an environmentally regulated waste
disposal scheme and
rigorous equipment maintenance procedures have been involved. Furthermore,
produced casing
gas often requires costly surface processing/treatment apparatus used to
separate, treat, and/or
recover casing gas components, in particular recovered steam. In the presently
described methods,
an alternative use for recovered gas is provided which reduces or eliminates
need for such surface
processing.
As will be understood, the methods and systems described herein are primarily
discussed in the
context of producing hydrocarbons from an underground reservoir. However, as
will be
understood, the presently described methods and systems allow for injection of
recovered gas back
downhole, the recovered gas potentially containing undesirable components such
as CO2 and/or
H2S. As such, it will be understood that methods and systems described herein
may, in certain
embodiments, be considered as methods and systems for managing recovered gas,
and/or as
methods and systems for sequestering CO2 and/or H2S downhole.
In another embodiment, there is provided herein a method for producing
hydrocarbons from at
least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
driven,
solvent-driven, or combined steam- and solvent-driven operation on the
underground
reservoir which includes:
injecting a solvent into the underground reservoir via an injection well in
communication with the underground reservoir;
31
CA 3014397 2018-08-17
recovering a fluid emulsion stream and a casing gas stream from the
underground reservoir
via a producer well in communication with the underground reservoir, the fluid
emulsion
stream being produced through a production tubing string of the producer well
and
comprising produced hydrocarbons, and the casing gas stream being produced
through a
casing channel of the producer well, wherein the fluid emulsion stream and the
casing gas
stream each comprise a recovered gas component comprising at least some of the
injected
solvent;
recycling the solvent by:
collecting the recovered gas from the fluid emulsion stream, optionally by
heating
the fluid emulsion stream, subjecting the fluid emulsion stream to a pressure
drop,
or both;
optionally, combining the collected solvent-containing recovered gas from the
fluid
emulsion stream with the solvent-containing recovered gas from the casing gas
stream;
optionally, mixing the recovered gas with steam, solvent, gas, liquid or a
combination thereof; and
re-injecting at least some of the recovered gas downhole via the same, or a
different,
injection well to mobilize hydrocarbons in the underground reservoir with
which
said injection well communicates; and
producing hydrocarbons from at least one underground reservoir into which the
solvent
and/or recovered gas is injected.
As will be understood, the recovered gas may be collected from the fluid
emulsion stream using
any suitable separation technique known in the art. By way of example,
separation may be
achieved by heating the fluid emulsion stream, subjecting the fluid emulsion
stream to a pressure
drop, or both. In certain embodiments, a low pressure degasser or separator
may be used to collect
the recovered gas from the fluid emulsion. Where recovered gas is obtained
from a produced fluid
32
CA 3014397 2018-08-17
emulsion stream, this recovered gas may be used for the recycling step either
alone, or in
combination with recovered gas from a produced gas stream (if available).
Cooling may be used
for separation of a recovered gas stream. For example, water and/or propane
can be removed from
a methane/propane/water mixture by cooling.
In yet another embodiment, there is provided herein a method for producing
hydrocarbons from at
least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
driven,
solvent-driven, or combined steam- and solvent-driven, or gas-lift operation
on the
underground reservoir which includes:
injecting a solvent into the underground reservoir;
recovering a fluid emulsion stream from the underground reservoir, the fluid
emulsion
stream comprising produced hydrocarbons and a recovered gas, the recovered gas
comprising at least some of the injected solvent and being entrained in the
fluid emulsion
stream;
recycling the solvent by:
collecting the recovered gas from the fluid emulsion stream, optionally by
heating
the fluid emulsion stream, subjecting the fluid emulsion stream to a pressure
drop,
or both;
optionally, mixing the solvent-containing recovered gas with steam, solvent,
gas,
liquid or a combination thereof; and
re-injecting the recovered gas into the same, or a different, underground
reservoir
to mobilize hydrocarbons therein; and
producing hydrocarbons from at least one underground reservoir into which the
solvent
and/or recovered gas is injected.
In still another embodiment, there is provided herein a method for producing
hydrocarbons from
33
CA 3014397 2018-08-17
at least one underground reservoir, said method comprising:
mobilizing hydrocarbons in the underground reservoir by performing a steam-
assisted
gravity drainage (SAGD) operation on the underground reservoir which includes:
injecting steam and a solvent into the underground reservoir via an injection
well
in communication with the underground reservoir;
recovering a fluid emulsion stream and a casing gas stream from the
underground reservoir
via a producer well in communication with the underground reservoir, the fluid
emulsion
stream being produced through a production tubing string of the producer well
and
comprising produced hydrocarbons, and the casing gas stream being produced
through a
casing channel of the producer well, wherein the fluid emulsion stream and the
casing gas
stream each comprise a recovered gas component comprising at least some of the
injected
solvent;
recycling the solvent by:
collecting the recovered gas from the fluid emulsion stream, casing gas
stream, or
both;
mixing the recovered gas with steam to form a mixed stream comprising steam
and
the solvent-rich recovered gas;
re-injecting the mixed stream downhole via the same, or a different, injection
well
to mobilize hydrocarbons in the underground reservoir with which said
injection
well communicates; and
optionally, producing hydrocarbons from the underground reservoir into which
the mixed
stream is injected.
In the presently described methods, the recovered gas, once at surface, may be
collected, optionally
compressed and/or heated to a suitable temperature and/or pressure, and
optionally mixed with
steam, solvent, gas, or a combination thereof, to form a mixed stream for re-
injection downhole.
34
CA 3014397 2018-08-17
Contrary to traditional processes, the need for a complex recycling and
separation facility may be
avoided with the presently described methods and systems. In particular, in
the presently described
methods the recovered gas may reinjected and reused without fractionation, CO2
removal, and/or
H2S removal. In other words, the casing gas may be used without additional
processing. As will
be understood, any of the recovered gas, the steam, and/or the mixed stream
may be compressed
and/or heated as desired in preparation for re-injection downhole, or the
mixed stream may be re-
injected downhole without prior compression and/or heating. It will further be
understood that the
recovered gas may contain some light gases (i.e. lighter than propane), for
example methane, that
do not really aid in solvent process and in turn, may reduce oil rates.
Removing these gases is
expensive. The present invention enables the avoidance of removing these gases
and a degree of
impurity in the recycled gas is acceptable. Furthermore, under any
fractionation system, it is
understood that some solvent will be lost along with the lighter gas.
Employing the concepts
described herein, all the solvent may be re-injected, thus avoiding such
losses.
It will be appreciated that recovered solvent/gas from the emulsion may have a
smaller
concentration of methane than the casing gas.
Temperatures and pressures of the recovered gas, and/or mixtures thereof,
intended for re-injection
in the recycling step may be selected to suit a particular application and/or
hydrocarbon production
system. By way of non-limiting example, and for the purposes of illustration,
a steam dominated
process (e.g., SAGD or a steam dominated SAP) may typically inject at 180-255
C and 2-4 MPa;
a solvent dominated or solvent-only process [2-4MPa] may typically inject at
(a) 60-100 C for
propane (b) 100-150 C for butane, or (c) 150-200 C for pentane, and the
temperature for
"condensate" may be higher: and a solvent-dominated or solvent-only process [1-
2MPa] may
typically inject at (a) 30-75 C for propane, (b) 50-125 C for butane, or (c)
115-175 C for pentane,
and the temperature for condensate may be higher. It will be understood that
these values are only
examples, and may be modified as needed or desired. As will also be
understood, a mix of
propane/butane/other gases (including water vapour) may have a different
temperature associated
therewith, for example. Ranges provided here are based on the alkane bubble
point curve shown
in Figure 21. For the steam dominated process, the temperature is based on the
saturation
temperature of steam with some consideration given to the cooling effect of
solvent.
CA 3014397 2018-08-17
In certain embodiments of the above-described methods, the recovered gas may
be mixed with
steam, solvent, gas, or a combination thereof. By way of example, in certain
embodiments, the
recovered gas may be mixed with steam, solvent, gas, or a combination thereof,
to form a mixed
stream. In certain examples, mixing may be may be achieved using an eductor,
such as the eductor
described in Canadian patent application no. 2,884,990, which is herein
incorporated by reference
in its entirety. Suitable eductors may include, for example, those having a
motive fluid inlet which
receives steam or another carrier (for example, steam from a slip-stream of
steam taken from an
upstream region of a high pressure steam source), a suction fluid inlet which
receives the solvent-
rich recovered gas, a motive fluid nozzle which compresses and accelerates the
steam (or other
carrier) through a diffuser throat causing a Venturi effect within the eductor
and compressing and
accelerating the suction fluid (i.e. the recovered gas) input via the suction
fluid inlet, a mixing
region including a converging inlet nozzle, a diffuser throat, and a diverging
outlet nozzle, the
outlet nozzle leading to a mixed stream outlet for outputting the mixed
stream.
In certain embodiments, the recovered gas may be mixed using a pump, multi-
phase pump, or
compressor, or another suitable mixing apparatus known to the person of skill
in the art having
regard to the teachings herein.
The output mixed stream may then be re-injected downhole. The mixed stream
may, in certain
embodiments, be mixed with additional steam, solvent, gas, or a combination
thereof before or
during re-injection downhole. By way of example, in certain embodiments, the
mixed stream may
be injected into a downstream region of the high pressure steam source prior
to the high pressure
steam source reaching the injection well.
In certain embodiments of the methods described herein, the mobilizing step
may be conducted
alongside the step of recycling. Because the recovered gas contains solvent,
the amount of solvent
used in the mobilizing step (i.e. the amount of "make up solvent") may be
reduced or eliminated
immediately, or gradually over time, in favour of the solvent contained in the
recovered gas being
re-injected in the recycling step. As such, in certain embodiments, the
recovering and recycling
steps may result in solvent recycling which may reduce or eliminate the use of
make-up solvent in
the mobilizing step, and may replace the solvent injection of the mobilizing
step partially or
entirely overtime. The amount of solvent injected may remain generally
constant or may be varied
36
CA 3014397 2018-08-17
over time. The volume of make-up solvent to be used may be determined based
the desired volume
of solvent to be injected.
As will be understood, in certain embodiments, the recovering and recycling
steps may be
performed two or more times. Such an approach may be used to recycle the
solvent originally
introduced in the mobilizing step, which may enhance efficiency. In this
manner, solvent may be
re-used two or more times without requiring traditional, generally costly,
solvent separation and
processing apparatus at the surface. In particular, in the presently described
methods solvent does
not need to be separated from water vapour, lighter components, and other
gases. Since the
collected recovered gas will typically comprise at least some of the injected
solvent, methane, H2S,
and/or CO2, such an approach may, in certain embodiments, reduce surface H2S
and/or CO2
processing requirements due to re-injection of these components back downhole
(i.e.
sequestration). In certain embodiments, such methods may decrease the amount
of recovered gas
pumped back to the plant, thereby reducing piping requirements and/or
maintenance, and/or may
allow recovered gas piping to be repurposed for delivering, for example,
solvent to the pad.
As will be understood, the recovering and recycling steps may be performed in
either a step-wise
staged fashion, in a batch form, or may be performed substantially
continuously (i.e. while newly
produced recovered gas is being collected, previously collected recovered gas
is being re-injected,
thereby maintaining a substantially continuous flow of recovered gas through
the system).
References herein to iterations or cycles of recovering and recycling steps
will therefore be
understood as encompassing both step-wise staged iterations or cycles, and
continuously operating
iterations or cycles which lack a clearly delimited cycle/iteration beginning
and end. Thus, in
certain embodiments involving continuous operation, references to performing
recovering and
recycling steps more than once, in more than one cycle, or in more than one
iteration, may be
considered as encompassing embodiments where the recovered gas recovery and
recycling is
performed over a duration which is sufficiently long to allow for at least one
initial volume of the
produced recovered gas stream to fully progress through the system and become
injected back
downhole, and then be followed by at least one subsequent volume of the
recovered gas to fully
progress through the recovering and recycling system and also become injected
back downhole.
In certain further embodiments, transition from one iteration or cycle to the
next may occur when
37
CA 3014397 2018-08-17
recovered gas re-injected in the current iteration or cycle is produced back
to the surface for re-
injection in a subsequent iteration or cycle.
In certain embodiments where more than one recovering and recycling iteration
is performed, the
recovered gas may become progressively enriched with lighter hydrocarbons with
each cycle of
recovering and recycling over time. By way of example, if condensate is used
as the solvent, then
the content of the produced recovered gas may contain lighter hydrocarbons
(e.g., Ci-C7 alkanes)
as compared with the content of the initially injected condensate. In certain
such embodiments,
heavier hydrocarbons may be pumped to the treating facility along with the oil
of the fluid
emulsion, while lighter hydrocarbons may be retained and reused in the
presently described
methods. Over time, the efficacy of the methods may thus improve, and/or the
need for surface
fractionation facilities may be reduced or eliminated in certain embodiments.
In such fashion, the
reservoir may be used to separate a mixture of heavy and light solvents
without requiring a
distillation system. In certain embodiments, the first pad may be the one with
the best containment
(so that condensate loss is prevented). If a good stream of light hydrocarbon,
such as a pentane-
rich stream is produced, this may be used in processes other than steam driven
processes such as
diluent addition to the central plant treating train. A preferred example
might be a solvent driven
process or other surface operations such as solvent deasphalting or oil water
separation processes.
In certain embodiments, solvent recovery may be initiated as soon as the
relevant processing
equipment is installed (e.g. on the same day that solvent injection is
initiated). Alternatively,
solvent recovery may be initiated based on a condition-set trigger. The
trigger may be, for example,
a flow-rate trigger. The flow-rate trigger may be based on the total flow rate
of the casing gas
stream, the produced fluid emulsion stream, or a combination thereof. For
example, solvent
recovery may be initiated when total gas flow within the casing stream is
greater than about 2
tonnes / day (in particular greater than 4 tonnes / day). The flow rate
trigger may alternatively be
based only on the solvent component of the casing gas stream, the produced
fluid emulsion stream,
or a combination thereof For example, solvent recovery may be initiated when
the solvent
component of the casing gas stream reaches a certain flow rate such as greater
than about 1.5
tonnes / day (in particular greater than about 3 tonnes / day). Alternatively,
the trigger may be a
concentration trigger based on the casing gas stream, the produced fluid
emulsion stream, or a
38
CA 3014397 2018-08-17
combination thereof For example, solvent recovery may be initiated when the
solvent component
of the casing gas stream accounts for greater than about 50 mol% as measured
on a dry basis (in
particular greater than about 75 mol% of the casing gas stream as measured on
a dry basis).
Alternatively, the condition-set trigger may be a production-based trigger
such as bitumen-
recovery factor. Those skilled in the art, having the benefit of the teachings
of the present
disclosure, will be able to select condition-set triggers (flow-rate,
concentration, production-based,
or other) having regard to, for example, the cost/availability of make-up
solvent, the
cost/availability of recycling infrastructure, and/or the price of produced
hydrocarbons.
As will be understood, in certain embodiments, the recovered gas may be re-
injected through the
same injection well through which the solvent was previously injected in the
mobilizing step, or
may be re-injected through a different injection well or other injection line
located on the same or
a different well pad and/or contacting the same or a different hydrocarbon
reservoir. In certain
embodiments, the injection well of the recycling step may be a different
injection well located on
a first well pad which is shared with the injection well used in the step of
mobilizing. In another
embodiment, the injection well of the recycling step may be a different
injection well located on a
second well pad, which is distinct from the injection well used in the step of
mobilizing located on
a first well pad.
As will be understood, in certain embodiments, the injection point used in the
step of recycling
may be selected in order to improve or maintain a desired field performance.
By way of example,
fresh solvent may be injected into large pads, and then recovered gas
containing at least some of
the solvent (which may be obtained after one or a plurality of recycling
iterations) may be used for
poor or old pads at or near the blowdown stage, for example. In one
embodiment, pads that have
reached the blowdown stage may be used to "store" solvent such as propane. In
another
embodiment, the blowdown stage may be entered into earlier and the blowdown
gas may be a
solvent, such as propane, instead of the more traditionally used NCG such as
methane.
In certain embodiments, a gas chromatograph, tunable filter spectrometer or
mass spectrometer
may be used for online measurement of recycled solvent in the produced gas,
which may drive the
continuous control of the amount of makeup solvent being used. Other
measurement tools, such
as those determining temperature, pressure, composition, and/or flow may also
be used. Ensuring
39
CA 3014397 2018-08-17
that the recovered gases are conditioned and mixed in such a way that they re-
enter the reservoir
at a suitable temperature, pressure such that the stream injected into the
reservoir is injected
primarily as a gas.
In certain embodiments, produced gas and/or produced fluid emulsions may be
conditioned using,
for example, a screen to remove bitumen, controllers to monitor the
concentration of contaminants
such as H2S, and/or an inline mixer. The concept behind conditioning the
emulsion is to ensure the
composition of the injected gas into the reservoir is suitable. The
composition may be conditioned
to remove entrained particulates and contaminants (H2S, NCG,). If the
concentration(s) of
contaminants are too high within the injected gas, they may impact operations.
Further, the
emulsion may be conditioned to ensure that the composition is well mixed when
the recovered gas
hits steam. In one embodiment, the composition may have a turbulent flow when
the recovered
gas hits steam or a solvent stream being injected so that it is well mixed.
Because recovered gas may include methane, it is contemplated that in certain
embodiments,
methane (CH4) in the recovered gas may form an insulating blanket and may be
affect steam
chamber development during early SAGD stages. Thus, in certain embodiments,
the recycling step
may be performed after the early SAGD stages involving chamber development
have been
completed, where a SAGD operation is performed.
Furthermore, in certain embodiments where the recovering and recycling steps
are performed more
than once or substantially continuously, the build-up of non-condensable gases
in the underground
reservoir (such as methane, see paragraph above) may be reduced or avoided by
performing the
step of recycling at a different injection well with each iteration, or after
a particular number of
iterations selected based on reservoir conditions and/or ongoing reservoir
monitoring, or after a
particular duration of time or injection volume threshold has been reached, or
by alternating back
and forth between two or more different injection wells, for example.
By way of example, in certain embodiments the steps of recovering and
recycling may be
performed more than once, and may cascade from one distinct well or well pad
to the next as the
operation progresses. Such embodiments are also described herein as Cascading
methods.
As will be understood, for a particular pad, wells will typically be in
communication with one
CA 3014397 2018-08-17
another. As such, in certain embodiments, it is contemplated that recovered
gas may be re-injected
at the recycling step at an increased pressure, thereby causing at least some
of the recovered gas
to migrate to at least one other well located on the same well pad, or at
least one other well located
on a communicating well pad. For setups utilizing multiple pads where the pads
"leak" into each
other, it is contemplated that recovered gas may be pushed or "flooded" from
one pad to another.
In certain embodiments, it is contemplated that where pads, wells, or pods
(see below) are in
pressure communication with each other in the subsurface, methods described
herein may be used
and may result in migration through the subsurface. In certain embodiments,
for example, re-
injection well(s) and production well(s) may be in subsurface communication.
In certain
embodiments, wells, pads, or pods may be operated at different pressures as
desired to facilitate
flooding across wells, pads, or pods.
In certain embodiments employing such recovered gas flooding, the cascade may
be performed
without having to actually produce the recovered gas in at least some
instances. Rather, the solvent
is pushed from one pad to another. As an example, if a pad is operated at 3200
kPa and another at
2800 kPa, it is expected that, if the steam/solvent chambers are contiguous or
in communication,
then some of the fluids will move from one chamber to the other. How much
material will flow
(and how fast) will depend on the area of the common border, the distance
between the two
chambers, the permeability of the reservoir, the fluid viscosity, and the
pressure difference (see
Darcy's equation: Q¨kA(pa-pb)/mu/L). Given that the viscosity of gas is less
than bitumen or
liquid water, if there is a pathway for gas to migrate it will do so faster
than liquid fluids. As a
result, it is expected that propane, methane, steam, and other gases may be
"pushed" by the
pressure difference from one pad to another. Propane may therefore be injected
at one pad, but
expected to be produced, in at least some amount, at other pads that are in
communication (and at
lower pressure) with the injection pad.
In certain embodiments, the recycling step may be applied on a "pod" scale, or
groups of pads. By
way of example, a group of, for example, 5 pads may be used at a certain
volume of solvent
injection, e.g. 15 wt%, and a re-injection operation may be set up at a
combined trunkline to those
initial 5 pads, and the solvent-containing recovered gas may be cascaded down
to a subsequent 5
pads, for example. In other words, recovered gas may be cascaded from one well
to the next, from
41
CA 3014397 2018-08-17
one well pad to the next, from one pod (or grouping) of wells to the next, or
any combination
thereof.
In certain embodiments, the solvent-containing recovered gas may be obtained
from one or more
wells or well pads, and/or may be distributed to one or more wells or well
pads. As will be
.. understood, the systems and methods described herein do not require all
wells/well pads of a given
network to operate under the same hydrocarbon mobilization technique. For
example, one well
may be operated under a steam driven solvent process, while another may be
operated as a solvent
driven well, and recovered gas from these wells may be used to drive, for
example, another SAP
pad. As will be understood, various configurations and combinations of well
and well pad
networks may be used depending on the particular application.
As will also be understood, cascading methods described herein may form a
network allowing an
operator to select where, and when, recovered gas is to be recovered and/or
recycled across the
network. As well, in certain embodiments, recovered gas may be recovered from
a produced gas
stream at the pad level and additional recovered gas may be recovered from the
fluid emulsion at
the pod level, or vice versa, for example.
Figure 27 illustrates the baseline Cascade concept. As shown in Figure 27, the
solvent Cascade
involves the joint operation of at least two wells where solvent is co-
injected with steam. The
solvent process on Well 1 is operated by co-injection of steam and a solvent
into the reservoir.
The solvent process on Well 2 is operated by co-injection of steam, and a
solvent rich gas stream
recovered from Well 1, into Well 2. Additional make up solvent may also be
added to Well 2, as
needed.
In certain embodiments, where the present methods are performed on an
underground reservoir
which is undergoing a reversible aquathermolysis reaction, the step of
recycling may be used to
drive the equilibrium of the aquathermolysis reaction away from the production
of H2S, decreasing
.. hydrogen sulfide production from the reservoir due to le Chatelier" s
principle (i.e. by adding H2S,
and/or by lowering the operating temperature):
Bitumen + Steam H2S + CO2 +
42
CA 3014397 2018-08-17
As will be understood, by using the presently described methods the recovered
gas may be used
substantially as produced, removing the need for wellhead separation step(s)
at the surface. In
certain embodiments, the recovering and recycling steps may reduce or
eliminate potentially costly
casing gas surface processing and treatment requirements.
As will be understood, as the volume of solvent injected into the reservoir is
increased, the % of
solvent in the recovered gas will also increase. In certain embodiments, this
may decrease the
volume of one or more of CO2. CH4, and H2S present in the casing gas. As will
be understood, less
CO2 may allow for higher rates with progressive recycling.
In certain embodiments, it is contemplated that recovered gas injection may be
performed for
adding heat to the reservoir. By way of example, for a solvent only operation,
for example VAPEX,
higher volumes of recycled solvent may be used to provide sufficient heat to
the reservoir for
effective oil drainage. In other words, in certain embodiments, solvent and/or
recovered gas may
be injected for providing heat to the reservoir even if only a portion of the
solvent is able to reach
the oil draining interface In one embodiment, the recovered gases may be used
to sustain part or
the entirety of a solvent dominant process, for example VAPEX or warm VAPEX.
For example,
the temperature of the recovered gas from one or more steam driven solvent
processes is likely
higher than the temperature required for a solvent driven process. In such a
case, the need for a
heating system within a solvent driven process may not be required.
In embodiments where recovered gas injection creates pressure buildup in the
reservoir, it is
.. contemplated that steam injection (if used) may be reduced. While this may
reduce SAGD
operation, lower steam rates may, in certain examples, cool the reservoir and
may increase the
solubility of the solvent in the oil. As a result, it may be an option to
operate at a lower temperature,
using less steam, and/or less energy (potentially under lower oil rates), in
certain embodiments. In
certain embodiments, a portion of the recovered gas may be slipstreamed back
into the fluid
emulsion line as desired in order to manage downhole pressure.
In yet another embodiment, there is provided herein a system for producing
hydrocarbons from an
underground reservoir, said system comprising:
a solvent source;
43
CA 3014397 2018-08-17
at least one well pad having a producer well in communication with the
underground
reservoir;
at least one collector for obtaining solvent-rich recovered gas from the
producer well; and
one or more injection lines in communication with the underground reservoir
for injecting
solvent from the solvent source, re-injecting the solvent-rich recovered gas
from the
collector, or a combination thereof, into the underground reservoir.
In still another embodiment, there is provided herein a system for producing
hydrocarbons from
an underground reservoir, said system comprising:
a solvent source;
at least one well pad having a producer well in communication with the
underground
reservoir;
at least one mixer for mixing solvent-rich recovered gas from the producer
well with steam,
solvent, gas, or a combination thereof, to provide a mixed stream; and
one or more injection lines in communication with the underground reservoir
for injecting
solvent from the solvent source, the mixed stream from the mixer, or a
combination thereof,
into the underground reservoir.
In another embodiment, there is provided herein a system for producing
hydrocarbons from an
underground reservoir, said system comprising:
a high pressure steam source;
a solvent source;
at least one well pad having a producer well in communication with the
underground
reservoir;
at least one mixer for mixing solvent-rich recovered gas from the producer
well with steam
44
CA 3014397 2018-08-17
from the high pressure steam source to provide a mixed stream; and
one or more injection lines in communication with the underground reservoir
for injecting
solvent from the solvent source, steam from the high pressure steam source,
the mixed
stream from the mixer, or any combination thereof, into the underground
reservoir.
In still another embodiment, there is provided herein a system for producing
hydrocarbons from
an underground reservoir, said system comprising:
a high pressure steam source;
a solvent source;
a producer well in communication with the underground reservoir, the producer
well
comprising a casing, a production tubing string inside the casing for
producing a fluid
emulsion stream comprising produced hydrocarbons to the surface, and a casing
channel
formed between the casing and the production tubing string for producing a
casing gas to
the surface, the casing gas comprising a solvent-rich recovered gas;
a mixer for mixing solvent-rich recovered gas from the casing channel with
steam from the
high pressure steam source to provide a mixed stream; and
an injection line for injecting the mixed stream into the underground
reservoir.
As will be understood, such systems may be configured for and used in
performing a method as
described hereinabove.
In certain embodiments of the systems described hereinabove, the mixer may
comprise an eductor
having a first inlet which is a motive fluid inlet, and a second inlet which
is a suction fluid inlet.
In certain embodiments, the mixer may comprise a first inlet which receives
steam from a steam
source such as, for example, a slip-stream of steam taken from an upstream
region of a high
pressure steam source, a second inlet which receives the solvent-rich
recovered gas, a mixing
region which mixes the steam and the solvent-rich recovered gas to provide the
mixed stream, and
a mixed stream outlet for introducing the mixed stream into a downstream
region of the high
CA 3014397 2018-08-17
pressure steam source prior to reaching the injection well.
In certain embodiments of the systems described hereinabove, the mixer may
comprise a pump,
multi-phase pump, or compressor, or another suitable mixing apparatus known to
the person of
skill in the aft having regard to the teachings herein. In embodiments where a
multi-phase pump
or multi-phase compressor is used, the system may further comprise a gas
cooler/chiller upstream
of the multiphase pump or multiphase compressor. Where a compressor is used,
the gas may be
heated to prevent formation of liquid.
In certain embodiments, the system may further comprise a dehydrator, which
would remove the
water content of the recycling stream. A dewatered stream can then be stored,
pumped and
pipelined more cost effectively through the avoidance of insulation and heat
tracing.
In certain embodiments, the system may further comprise a 3-phase separator
for obtaining solvent
from the recovered gas. The 3-phase separator under certain conditions will
produce a rich solvent
portion, water rich portion and vapour portion. This rich solvent portion may
be redirected to
storage, pumping and pipelining more cost effectively through the avoidance of
insulation and heat
tracing. While this type of system may not provide discrete components, the
bulk separation may
be advantageous through reduced costs, ie for re-injecting the water rich
portion in the existing
pad, while sending the water free solvent to farther pads.
In certain embodiments, systems described herein may further comprise a
collector for collecting
the solvent-rich recovered gas stream. In embodiments where recovered gas is
to be obtained from
a produced fluid emulsion, the collector may comprise apparatus for heating
the fluid emulsion,
subjecting the fluid emulsion to a pressure drop, or both. In certain
embodiments, cooling may be
applied to the resultant vapours. In certain embodiments, the collector may
comprise a low
pressure group separator, or a settling tank.
In certain embodiments, a heating and/or depressurizing apparatus may be
included for generating
recovered gas from fluid emulsions. In certain embodiments, a pump or
compressor may be
included for compressing recovered gas for subsequent re-injection. Where a
pump or compressor
is included, a cooling or heating apparatus may also be included for cooling
sufficient liquid to
(i.e. condensate) to allow operation of a multiphase pump of (for example) an
SAP operation, or
46
CA 3014397 2018-08-17
for heating to re-vaporize the solvent mixture of (for example) a solvent only
operation prior to re-
injection.
As will be understood, many different system configurations may be
contemplated depending on
the particular application, hydrocarbon deposit, well architecture, and/or
method to be performed,
.. and many modifications, substitutions, additions, or deletions may be made
to adapt the system
for performing any of the methods detailed herein. By way of example, where
the collected
recovered gas stream is to be compressed and/or heated, the system may
additionally comprise a
suitable compressor and/or heater. By way of example, a multiphase pump may be
used for
compressing the recovered gas in certain examples.
In certain embodiments, the collector and/or mixer may obtain solvent-
containing recovered gas
from one or more wells or well pads, and/or may distribute recovered gas to
one or more wells or
well pads. As will be understood, the systems and methods described herein do
not require all
wells/well pads to operate under the same hydrocarbon mobilization technique.
For example, some
well pads may be operated under steam driven SAP, while another may be
operated as a solvent
driven well, and recovered gas from these wells may be used to drive, for
example, another SAP
pad. As will be understood, various configurations and combinations may be
used depending on
the particular application.
In certain embodiments, a multiphase compressor may be used to impart suction
on the casing
channel, and discharge into a steam injection line for a particular well.
Casing gas pressure may
be used to control compressor VFD to maintain the appropriate back pressure. A
discharge
pressure shutdown may be installed to prevent the compressor from
overpressuring the steam line.
The compressor discharge may also have a slipstream control valve to send a
portion of the casing
gas into the fluid emulsion or casing channel line if desired due to reservoir
gas loading. The
multiphase compressor may use 5% liquid to maintain the seal for the twin
screws. Two main
options for providing this liquid may include: The emulsion may be slip
streamed into the
compressor suction, or alternatively a easing gas cooler may be installed to
condense enough steam
to provide sealing liquid. The following are example parameters for a
multiphase pump:
Inlet pressure of about 1,000 kPag (500 kPag up to 2,500 kPag range)
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Inlet temperature of 200C (50C to 220C range)
75% steam (with the remaining methane and propane, for example) (20% to 90%
steam
range).
In certain embodiments of the systems described above, the mixer may comprise
an eductor in
which the first inlet is a motive fluid inlet, and the second inlet is a
suction fluid inlet. Examples
of suitable eductors are already described above.
In certain embodiments of the above systems, the mixer and/or collector and/or
other system
components may be modular and/or portable, and may be moved between injection
and producer
well pairs and/or between well pads as desired to perform the presently
described methods at
different locations and/or sites.
In certain embodiments, the systems described herein may be free of wellhead
separation
apparatus, since the recovered gas stream may be produced to the surface
separately from the fluid
emulsion, and/or readily recovered from the produced fluid emulsion stream
without need for
separation or degassing.
In certain embodiments of the above systems, the injection line and the
producer well may be part
of a single SAGD well pair, may be are located on the same well pad, or may be
located on different
well pads.
EXAMPLE 1¨ METHOD AND SYSTEM FOR PRODUCING HYDROCARBONS FROM
AN UNDERGROUND RESERVOIR UNDER SAGD OPERATION
An example of a method and system for producing hydrocarbons from an
underground reservoir
which is under SAGD operation is described in further detail below with
reference to Figure 3.
In Figure 3, a solvent-assisted SAGD system is depicted for producing
hydrocarbons from an
underground reservoir via a method as described herein. A high pressure steam
source (1) and a
solvent source (2) are provided. The solvent in this example is butane. The
solvent is mixed with
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the steam at junction (3), and injected downhole via an injection well (10).
The steam and solvent
mobilize hydrocarbons in the underground reservoir, which drain into a
producer well (11). The
producer well (11) includes an inner production tubing string (13), through
which the reservoir
hydrocarbons are produced to the surface as part of a fluid emulsion stream
via an electric
submersible pump (ESP). The producer well (11) also includes an outer casing
(12), and an annular
casing channel formed between the outer casing (12) and the inner production
tubing string (13).
During operation, recovered gas is produced to the surface, separate from the
fluid emulsion
stream, in a casing gas stream which travels through the casing channel to the
surface. The casing
gas stream (14), which contains solvent-rich recovered gas, is collected and
mixed with a slip
.. stream of steam (5) taken from the high pressure steam source (1) at an
upstream region (4) in a
mixer (6) which, in this example, comprises an eductor as described
hereinabove, to form a mixed
stream (7) which is introduced back into the high pressure steam source (1) at
a downstream
location (8), forming a steam/mixed stream mixture (9) which is injected into
the reservoir via, in
this example, the previously described injection well (10).
When the mixed stream (7) starts being introduced into the high pressure steam
source (1), the
solvent input from the solvent source (2) is decreased or eliminated either
immediately or
gradually, depending on the particular reservoir characteristics and/or
desired operational
parameters. Thus, the input of further solvent (i.e. "make-up" solvent) may be
reduced or
eliminated in certain embodiments.
In this example, the recovered gas recovery and recycling back downhole is
performed
substantially continuously. While previously produced recovered gas is being
re-injected
downhole, newly produced recovered gas is simultaneously being collected and
mixed in
preparation for injection back downhole behind the previously produced and re-
injected recovered
gas.
The system embodiment depicted in Figure 3 may include a compressor (in the
form of a
multiphase compressor) and a heater to compress and heat the comparatively low
pressure
produced casing gas stream while it is being collected, increasing the
temperature and pressure
prior to mixing with the slip stream of steam. The mixed stream, which is at
an intermediate
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pressure and temperature, is then mixed in with the high pressure, high
temperature steam source
and injected back downhole at a sufficient temperature and pressure to
mobilize hydrocarbons in
the underground reservoir.
In Figure 3, the hydrocarbon reservoir is undergoing reversible
aquathermolysis reaction, and the
recovered gas re-injection may add H2S downhole to at least partially drive
the aquathermolysis
reaction equilibrium away from the production of further H2S.
As depicted in Figure 3, the casing gas stream produced through the casing gas
channel is used
substantially as produced, and is not subjected to wellhead separation.
Performance of the method
over time results in solvent re-cycling, which reduces or eliminates the use
of make-up solvent in
the mobilizing step, and reduces or eliminates the burden of traditional
surface
treatment/separation/recycling equipment for recovering solvent and/or steam.
In the embodiment depicted in Figure 3, the slip stream of high pressure steam
(5) from the plant
is typically at approximately 7-8000kPag, and is taken from the steam source
(1), pressure dropped
(via a valve) to a wellhead pressure of 2-4 MPa typically, and redirected to
the eductor-type mixer
(6) to serve as motive fluid. As will be understood, a multi-phase pump may be
used rather than
the eductor in certain embodiments. The fluid emulsion produced by the
producer well typically
contains a percentage of gas; for example, approximately 20-30% of this gas
may entrained in the
produced fluid emulsion brought to the surface through the production tubing
string (13) and
directed back to the plant. Further, approximately 70-80% of the gas may be in
vapour form and
produced up through the casing channel and collected at the casing gas header.
The gas entrained
in the produced fluid emulsion and the produced casing gas stream collected at
the header are
substantially similar. In certain embodiments, the recovered gas containing
the solvent may be
removed from the produced fluid emulsion prior to sending the fluid emulsion
to the plant, and the
removed recovered gas may be combined with the recovered gas of the casing gas
stream for
subsequent recycling.
The eductor-type mixer (6) represents a relatively inexpensive mixer for
controlling pressure, and
may be utilized to boost the pressure of the casing gas such that it is
adapted for injection into the
reservoir; a multiphase pump may alternatively be used. The casing gas may
typically be at a
CA 3014397 2018-08-17
pressure range of 1200-1500 KPag. The eductor may mix the slip stream of high
pressure steam
with the low pressure casing gas and produce a mixed stream (of steam and
recovered gas) having
a pressure of about 3-4000kPag.
The high pressure steam from the plant may undergo a pressure drop to bring
the steam to a
pressure suitable for injection into the reservoir, which may typically be
controlled by the bottom
hole pressure. The mixed stream may be recombined with the reduced pressure
steam from the
plant, and then injected into the reservoir. While the produced casing gas may
have a nominal
amount of entrained liquid, there is no wellhead separation of this liquid
from casing gas in these
embodiments.
A suitable injection pressure may be obtained for the injection well; however,
in certain
embodiments methods and systems described herein do not require throttling of
the mixed streams.
Plants typically have an existing throttling valve on the high pressure steam
line to the injection
well, and embodiments of systems described herein may take a slip stream off
the high pressure
steam line prior to throttling, and utilize this slip stream as input to the
eductor. The recovered gas
may enter the eductor at a lower pressure, and a first mixed stream is may
thus be created at an
intermediate pressure. The first mixed stream may be combined with now-
throttled high pressure
steam in the steam line, and the second mixed stream may then be injected into
the injector well
at a suitable pressure without need for an additional throttling step.
It is contemplated that any suitable volume of solvent/steam injection may be
used with the
presently described systems and methods. For example, about 2 wt% up to about
100 wt% solvent
injection may be used in certain embodiments. When about a 10 wt% butane and
90 wt% steam
mixture is injected through the injector well in the SAP, the casing gas
produced through the
producer may be about 80 wt% steam (with relatively low pressure and
temperature) and about 20
wt% gases, of which about 80-85 wt% is may be butanes (C4), about 12-14 wt%
may be methane
(C1), and the remainder may include H2S, CO2 and other such gases. A
compressor may be used
to increase the temp/pressure of the casing gas stream to conditions suitable
such that the casing
gas may be re-injected into the steam line, with little or no cooling effect
on the steam.
EXAMPLE 2 ¨ MULTI-WELL HYDROCARBON PRODUCTION SYSTEM
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CONFIGURATION EXAMPLES
Figures 4-14 provide schematic drawings of a plurality of system embodiments
which are
configured for performing a hydrocarbon production method as described herein
in a multi-pad
setup using cascading of recovered gas. Various configuration embodiments are
depicted,
exemplifying the adaptability of the presently described systems and methods.
As outlined above, Figure 27 illustrates the simplest concept of the Cascade
concept. The solvent
Cascade shown in Figure 27 involves the joint operation of at least two wells
where solvent is co-
injected with steam. The solvent process on Well 1 is operated by co-injection
of steam and a
solvent into the reservoir. The solvent process on Well 2 is operated by co-
injection of steam, and
a solvent rich gas stream recovered from Well 1, into Well 2. Additional make
up solvent may
also be added to Well 2, as needed.
A basic 3-pad setup using propane and steam for mobilization is depicted in
Figure 4, where
recovered gas containing injected propane is cascaded from Pad 1 to Pad 2 to
Pad 3. Figure 5
employs multiphase compressors for preparing the recovered gas for injection
in the recycling
step, and further includes casing gas coolers to accommodate the multiphase
compressors. In
Figure 6, fluid emulsions produced from Pads 1-3 are processed in low pressure
group separators
to obtain solvent-rich recovered gas therefrom for cascade recycling to
subsequent wells. The
depicted system of Figure 6 additionally includes a chilling system and a 3-
phase separator
downstream from pad 3, the chilling system and 3-phase separator receiving the
produced casing
gas and fluid emulsion and outputting NCG which is sent to the plant, recycled
solvent (in this
case, propane) which is re-used as solvent for injection, and water which is
sent to the plant as part
of the hydrocarbon-containing emulsion. In Figure 7, a 3-pad configuration is
depicted which
employs both the low pressure group separator and the multiphase compressor.
In Figure 8, a
system similar to that shown in Figure 6 is depicted, but with the propane
output from the 3-phase
separator being directed back to each of Pads 1-3. Each of Figures 9-14 depict
additional variations
in configuration. Figures11-13 employ further a dehydrator, which would remove
the water
content of the recycling stream. A dewatered stream can then be stored, pumped
and pipelined
more cost effectively through the avoidance of insulation and heat tracing,
and Figure 12 employs
a group separator that combines the emulsion and casing gas streams in which
the vapour outlet is
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CA 3014397 2018-08-17
then treated the same as the casing gas in figure 11. This additional
combination and degassing at
low pressure allows more of the solvent to be recycled..
EXAMPLE 3¨ RESERVOIR SIMULATIONS
It is recognized that in certain embodiments, re-injection of recovered gas
may involve re-injection
of methane. Typically, for an early- to mid-life well, methane removal is
desired for obtaining
good oil rates. As a result, methane re-injection may lead to reduced oil
rates (even for a SAP
well). To estimate the potential oil rate penalty arising from re-injection of
casing gas containing
method, three simulations were run. All simulations were run on the same geo-
model and using
the same reservoir properties. The simulations were as follows:
1. A SAGD baseline
2. A steam driven SAP simulation with a SAP starting in day 1000, and 10%
C3 injection.
3. A steam driven SAP simulation, same as Run 2, with 10% C3 injection and
2% methane
injection.
The oil rate of each simulation is shown in Figure 15. The CSOR for each
simulation is shown in
Figure 16. As can be seen from Figure 15 and Figure 16, the re-injection of
methane did bring the
SAP oil rates down to the SAGD rates, but the SAP SOR advantage remained
roughly the same.
As SOR is generally the main economic and environmental driver associated with
a SAP, the
results of these simulations suggest that methane re-injection may have
minimal negative
economic and environmental consequences. Generally, field data for methane co-
injection has not
shown the dramatic reduction in oil rate predicted by the simulation. While we
use simulation
data in the above example, we expect field performance to be better based on
the experience of
other operators with co-injection of methane.
The methane re-injection simulation (Run 3) done in this section resulted in a
methane production
(and injection) rate of roughly 3.5t/d (full rates). This is roughly 3-4 times
the expected steady
state methane production rate for a SAP or SAGD well (based on Runs 1 and 2).
The higher
methane rate for Run 3 was used because methane re-injection may lead to
methane build up and
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higher methane production rates. Note, "expected steady state methane
production" is considered
for an 800 meter well at higher pressure. It would be understood that wells at
lower pressures will
generally produce less methane; and longer wells will generally produce more
methane.
EXAMPLE 4¨ CASCADING RECOVERED GAS
In this example, an embodiment of a pad wide SAP recycling system is
described. By taking a pad
wide approach to casing gas recycling via re-injection, a solvent recycling
system is described
which may allow for relatively reduced costs.
Traditional solvent recycling facilities are expensive. Furthermore, a
centralized recovery facility
may be difficult to modify or re-engineer as solvent technology evolves. For
example, as greater
concentrations of solvent is used, the temperature of the produced fluids may
decrease, as may
their asphaltene content, triggering a redesign of the recovery facility.
An alternative approach is described herein, whereby small pad-scale recycling
facilities may be
built, which may be modular, portable, and/or upgradable. In such an approach,
propane (and
other lighter hydrocarbon components) may be separated from the bitumen. The
propane (and
other lighter components) may then be re-injected with substantially no
further separation. The
lighter components (and associated water vapour) are not removed before re-
injection. The
approach described herein below may be referred to as "Cascading" solvent
recycling. Cascading
may represent a simple recycling system design in which the propane, lighter
components, and
water vapour (collectively called the "recovered gases" or "casing gas
stream") from one well, pad
or pod and may be re-injected into another well, pad, or pod (or, in some
cases the same pad). By
re-injecting into a different pad, non-condensable gases may not substantially
build up in the
reservoir. However, re-injection into the same pad may also be possible and,
in some cases,
preferred. One example where re-injection into the same pad may be preferred
may include a
blowdown or near-blowdown strategy.
In Cascading methods including re-injection to new pads, solvent may be more
efficiently applied
on a substantially field-wide basis. If solvent price is high, or if solvent
supply is limited, this may
be desirable. By way of example, a Cascade method where a series of pads are
connected so that
the recovered gases from one pad may be injected into the next pad forming a
cascade of five pads
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CA 3014397 2018-08-17
and only 450 t/d (roughly 11 trucks/day) of solvent are available may be
considered. Table 2
provides a comparison of two SAP implementations (and a SAGD baseline) for
such a five pad
system. The first SAP implementation is a "traditional" implementation with a
full recycle system
and 15%wt propane injection. The second implementation is the newly described
Cascading
scheme detailed herein. It is assumed that each pad has ten wells and that
each well uses 300t/d
of steam. As shown in Table 2, the traditional approach of full recycle will
produce an average
solvent wt% injection of 9% and a simulated average SOR reduction of 22%. On
the other hand,
Cascading method results in an average of 8 wt% propane injection but a
(higher) simulated 26%
average reduction in SOR. The reason that the average SOR reduction is higher
under the
Cascading SAP scheme is that the solvent is spread over a larger number of
pads. In general,
several pads with a low injection rate will yield a higher average SOR
reduction than fewer pads
with a high solvent injection rate.
Table 2: Comparison of Full Recycle and Cascading SAP
SAGD 15% Propane SAP With Traditional Recycle Cascade SAP
Steam Steam SAP Propane Propane SOR
Reduction Steam SAP Propane Propane SOR Reduction
Inj Fresh Ini Fresh
t/d t/d wt % t/d t/d wt % t/d
PAD 1 3000 2550 0.15 450 150 37% 2550 15% 450
450 37%
PAD 2 3030 2550 0.15 450 150 37% 2703 10% 297
0 33%
PAD 3 3030 2550 0.15 450 150 37% 2804 7% 196
0 28%
PAD 4 3000 3000 0 0 0 0% 2871 4% 129 0
17%
PAD 5 3000 _ 3000 0 0 0 0% 2915 3% 85 0
15%
Sum 15000 13650 450 111% 13842 450
128%
Average 3030 2730 9% 22% 2768 8% 28%
Using cascading SAP may allow for relatively reduced cost, flexibility in
design and operation,
reduced need for large casing gas lines to handle produced solvent,
simplification of recycle system
design, relatively lower operating cost since the solvent does not require
separation from water
vapour, lighter components, and other gases, efficacious use of solvent in
terms of average SOR
reduction, and/or efficient use of solvent in terms of NPV if solvent supply
is limited.
In certain embodiments, Cascade concept may be applied on a "pod" scale, or
groups of pads. For
example, a first pod (pod 1) may comprise a series of 5 pads having a solvent
injection at 15 wt%.
A re-injection operation may be located at or near the combined trunkline to
those 5 pads of pod
CA 3014397 2018-08-17
1. The solvent-rich recovered gas from the first pod may be cascaded to
provide the solvent for a
second pod comprising a second group of 5 pads (pod 2).
In certain further embodiments, solvent injection concentration at the first
pad may be varied. In
Table 2, a value of 15 wt% was used in the initial injection pad. However, it
is contemplated that
a higher (or lower) solvent injection concentration may be used. Using a high
solvent concentration
may result in higher SOR reduction (if solvent was less costly and in
abundance), and hence higher
NPV. However, using a lower rate may result in lower capital cost and hence
higher PIR and IRR.
Furthermore, in one embodiment a volume of top-up solvent may be added at each
pad to enable
each pad in the sequence to have a tailored solvent volume for that pad.
In still further embodiments, the number of pads to be cascaded may be varied.
In a system with
many cascading pads, a higher initial concentration may be used. However, for
a system with only
two cascading pads, the capital may be lower. For example, if five pads are
used in the cascade
system, then four recovery systems may be used for a ratio of 4/5. If only two
pads are in the
system, then the ratio is 1/4.
In yet other embodiments, a higher initial injection concentration may be used
via a solvent
dominated process in the first pad or pads, and then the recovered solvent may
be used to apply
SAP to subsequent pads.
In yet another embodiment, the injection location in each pad may be varied.
Thus, for example,
high amounts of propane may be injected at one edge well with no producer. The
solvent may
then travel across the pads (assuming a pressure gradient exists), and may be
produced and
recovered in other wells. The increased subsurface path-length for propane may
reduce the amount
of propane produced, which may result in lower capital cost. Similarly, if
several pads are in
communication, injection may happen at only one pad and recovery/production
may happen from
all pads (i.e. to be subsequently re-injected elsewhere).
In a further embodiment, the produced fluid emulsion stream and the solvent-
rich recovered gas
stream may be commingled and directed to a group separator that may be
operated at relatively
low pressure, for example about 200kPag up to about 1000kPag. This low
pressure may enhance
flashing of the solvent. The vapourized solvent is then collected, cooled,
compressed and
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CA 3014397 2018-08-17
reinj ected.
In yet another embodiment, a chilling train may be included on the last pad in
a Cascade system,
such as a cascade SAP system. The chilling train may further include a
dehydration unit. When
recovering solvent on the last pad, the chilling train may assist in
exhausting the build-up of non-
condensible gases. The chilling train may include a dehydration step before or
after the chilling
exchanger, which allows a deeper cut of solvent from the vapour stream.
By re-injecting solvent along with other gases (i.e. impure solvent), certain
costs associated with
solvent recycling may be reduced or avoided. Also, by re-injecting into nearby
pads, expense of
a large casing gas line may be reduced. In another aspect, the development of
smaller-scale
recycling facilities and/or smaller scale solvent recycling operations that
may be more quickly
adaptable to new technology and/or conditions as they arise ( for example, new
operating strategy,
new reservoir conditions, presence of a gas cap, change in the price of
solvent, etc...) is
contemplated.
By way of example, a series of three pads may be considered. The first is Pad
A, having 6 wells.
Each of the subsequent pads, Pad B and Pad C, have 8 wells. It is may be
assumed that each well
requires 300t/d of steam, and that steam demand will not drop with SAP SAGD
(although SOR
likely will). The equally likely case where steam demand drops may also be
considered. A
schematic showing relevant flow rates for steam, propane, and methane for this
system is shown
in Figure 17.
As shown in Figure 17, operating three pads on solvent-assisted SAGD with an
average injection
concentration of roughly about 8 wt% propane may be done while keeping the
maximum methane
injection under about 0.6%, and burning only about 13% of injected propane.
The scheme shown
in Figure 17 uses only two recycling facilities, and produces a simulated
average SOR reduction
of about 24%. This approach may be replicated across the field as appropriate
and may allow
relatively quick implementation of SAP SAGD with relatively low capital
investment and/or good
IRR.
The effect of co-injection of non-condensable gases (e.g., methane) on
reservoir performance may
be a potential risk in this example. In simulation, a 0.6 wt% injection of
methane along with a
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solvent injection of 3 wt% propane in SAP SAGD resulted in a CSOR that is
within 2% of a SAP
SAGD operation at the same solvent injection with no methane co-injection and
an oil rate that is
within 10%. Both the CSOR and oil rates for the 0.6 wt% methane co-injection
simulation were
substantially improved over the SAGD base case having no solvent injected. A
plot of the CSOR
for all three cases is shown in Figure 18, and a plot of the oil rates is
shown in Figure 19.
In certain embodiments, it is contemplated that cascade methods, such as those
employing for
example, a 15% pad feeding a 7.5% pad feeding a 3% pad, may be used for
sending the plant feed
from the 3% pad and fluid emulsions from the 15% and 7.5% pads. As a result,
SAP operations
may be conducted without requiring substantial modification of the central
plant to accommodate
variation in the solvent concentration of the material injected during a SAP.
One or more illustrative embodiments have been described by way of example. It
will be
understood to persons skilled in the art that a number of variations and
modifications can be made
without departing from the scope of the invention as defined in the claims.
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