CA3014397A1 - Methods and systems for recycling recovered gas - Google Patents

Abstract

Provided herein are methods for producing hydrocarbons from a hydrocarbon reservoir, said methods including: mobilizing hydrocarbons in the underground reservoir by injecting a solvent; recovering a recovered gas containing at least some 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. Systems for performing such methods are also provided.

Description

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 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-

2 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

3 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-

4 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-

5 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

6 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.

7 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

8 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

9 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.

10 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

11 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;

12 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

13 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.

14 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.

15 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;

16 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.

17 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

18 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 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:

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.

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 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 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 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;

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 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 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 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 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 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;

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 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 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.

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.

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 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 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 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 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 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 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 +

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;

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 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 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 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) 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 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 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 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

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 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 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 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 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 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 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.

Claims (80)

WHAT IS CLAIMED IS:

1. 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, 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.

2. The method according to claim 1, wherein 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.

3. 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 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.

4. 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.

5. 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, 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.

6. 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;
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.

7. The method according to any one of claims 1-6, wherein 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.

8. The method according to any one of claims 1-7, wherein 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.

9. The method according to any one of claims 1-8, wherein the recovered gas is mixed with 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.

10. The method according to any one of claims 1-9, wherein the recovered gas is mixed with steam via an eductor or a multi-phase pump for re-injection in the recycling step.

11. The method according to any one of claims 1-10, wherein the recovering and recycling steps are performed more than once.

12. The method according to claim 11, wherein the recovered gas becomes enriched with lighter hydrocarbons with each cycle of recovering and recycling.

13. The method according to any one of claims 1-12, wherein the recycling step comprises compressing the gas, heating the gas, or both, prior to re-injecting.

14. The method according to any one of claims 1-13, wherein 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.

15. The method according to any one of claims 1-14, wherein the casing gas stream is subjected to wellhead separation or other separation of gas components.

16. The method according to claim 15, wherein the wellhead separation or the other separation of gas components provides a first stream that is used in the recycling step substantially as-produced.

17. The method according to claim 16, wherein the wellhead separation or the other separation of gas components further provides a second stream that is primed prior to re-injection or is not re-injected.

18. The method according to any one of claims 1-14, wherein 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.

19. The method according to any one of claims 1-18, wherein the recovering and recycling steps reduce or eliminate the use of make-up solvent in the mobilizing step.

20. The method according to any one of claims 1-18, wherein the recovering and recycling steps reduce or eliminate need for the mobilizing step.

21. The method according to any one of claims 1-20, wherein the recovering and recycling steps reduce or eliminate gas surface processing and treatment requirements.

22. The method according to any one of claims 1-21, wherein 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.

23. The method according to any one of claims 1-22, wherein 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.

24. The method according to claim 23, wherein 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.

25. The method according to any one of claims 1-24, wherein the steps of recovering and recycling are performed more than once, and cascade from one distinct well or well pad to the next.

26. The method according to any one of claims 1-25, wherein the steps of recovering and recycling are performed more than once, and cascade from one distinct well or well pad to the next, and wherein at least some re-injected recovered gas migrates between wells or well pads while underground.

27. The method according to 23 to 26, wherein the first and second well pads are comprised within the same pod.

28. The method according to any one of claims 23 to 26, wherein the first well pad is comprised within a first pod and the second well pad is comprised within a second pod.

29. The method according to claim 28, wherein the recovered gas obtained in the first pod is recycled to the second pod.

30. The method according to any one of claims 1 to 29, wherein the step of re-injecting the recycled gas includes injection at least a portion of the recycled gas near or at blowdown.

31. 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 injection well communicates; and optionally, producing hydrocarbons from the underground reservoir into which the mixed stream is injected.

32. The method according to claim 31, wherein 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.

33. The method according to claim 31 or 32, wherein the casing gas stream is mixed with steam via an eductor or a multi-phase pump.

34. The method according to any one of claims 31-33, wherein the recovering and recycling steps are performed more than once.

35. The method according to claim 34, wherein the recovered gas becomes enriched with lighter hydrocarbons with each cycle of recovering and recycling.

36. The method according to any one of claims 31-35, wherein the collected recovered gas is compressed, heated, or both, prior to re-injection.

37. The method according to any one of claims 31-36, wherein the recovered gas comprises a steam component and a gas component, the gas component comprising the solvent, methane, H2S, and c02.

38. The method according to claim 37, wherein 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 H2S, decreasing hydrogen sulfide production.

39. The method according to any one of claims 31-38, wherein the casing gas stream is subjected to wellhead separation or other separation of gas components.

40. The method according to claim 39, wherein the wellhead separation or the other separation of gas components provides a first stream that is used in the recycling step substantially as-produced.

41. The method according to claim 40, wherein the wellhead separation or the other separation of gas components further provides a second stream that is primed prior to re-injection or is not re-injected.

42. The method according to any one of claims 31-38, wherein the casing gas stream produced through the casing gas channel is used substantially as produced and is not subjected to wellhead separation.

43. The method according to any one of claims 31-42, wherein the recovering and recycling steps reduce or eliminate the use of make-up solvent in the mobilizing step.

44. The method according to any one of claims 31-43, wherein the recovering and recycling steps reduce or eliminate casing gas surface processing and treatment requirements.

45. The method according to any one of claims 31-44, wherein the injection well of the recycling step is the same injection well used in the step of mobilizing.

46. The method according to any one of claims 31-44, wherein 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.

47. The method according to any one of claims 31-44, wherein 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.

48. The method according to claim 34, wherein 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.

49. The method according to claim 46 or 47, wherein the first and second well pads are comprised within the same pod.

50. The method according to claim 46 or 47, wherein the first well pad is comprised within a first pod and the second well pad is comprised within a second pod.

51. The method according to claim 50, wherein the recovered gas obtained in the first pod is recycled to the second pod.

52. The method according to any one of claims 31-43, wherein the steps of recovering and recycling are performed more than once, and cascade from one distinct well or well pad to the next.

53. The method according to any one of claims 31-52, wherein the steps of recovering and recycling are performed more than once, and cascade from one distinct well or well pad to the next, and wherein at least some re-injected recovered gas migrates between wells or well pads while underground.

54. The method according to any one of claims 1-53, wherein the solvent comprises condensate, butane, propane, or any combination thereof.

55. The method according to any one of claims 1-54, wherein 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.

56. The method according to any one of claims 31 to 55, wherein the step of re-injecting the recycled gas includes injection at least a portion of the recycled gas as blowdown.

57. The method according to any one of claims 1 to 56, wherein the recovering step is initiated based on a condition-set trigger.

58. The method of claim 57, wherein the condition-set trigger is a concentration trigger.

59. The method of claim 57, wherein the condition-set trigger is a flow-rate trigger.

60. The method of claim 57, wherein the condition-set trigger is based on a production-based trigger.

61. The method of claim 60, wherein the production-based trigger is based on bitumen-recovery factor.

62. The method of any one of claims 1-61, which sequesters CO2, H2S, or a combination thereof in the at least one underground reservoir.

63. 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 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.

64. 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.

65. 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 steam source, the mixed stream from the mixer, or any combination thereof, into the underground reservoir.

66. 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.

67. The system according to any one of claims 63-66, for use in performing a method according to any one of claims 1-62.

68. The system according to any one of claims 65-67, wherein 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.

69. The system according to any one of claims 64-68, wherein the mixer comprises an eductor having first inlet which is a motive fluid inlet, and a second inlet which is a suction fluid inlet.

70. The system according to any one of claims 64-68, wherein the mixer comprises a multiphase pump or multiphase compressor.

71. The system according to claim 70, wherein the system further comprises a casing gas cooler upstream of the multiphase pump or multiphase compressor.

72. The system according to any one of claims 63-71, wherein 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.

73. The system according to any one of claims 63-72, wherein the system further comprises a dehydrator.

74. The system according to any one of claims 63-73, wherein the system further comprises a 3 phase separator for obtaining solvent from the recovered gas.

75. The system according to any one of claims 63-74, further comprising a compressor, heater, or both, for compressing and/or heating the recovered gas prior to injection.

76. The system according to any one of claims 63-75, wherein the recovered gas is used substantially as produced, and the system is free of wellhead separation apparatus.

77. The system according to any one of claims 63-76, wherein the system is modular, and one or more components can be moved between injection and producer well pairs and/or between well pads.

78. The system according to any one of claims 63-77, wherein the injection line and the producer well are part of a SAGD well pair.

79. The system according to any one of claims 63-78, wherein the injection line and the producer well are located on the same well pad.

80. The system according to any one of claims 63-79, wherein the injection line and the producer well are located on different well pads.