CA3074497A1 - Carbon dioxide removal from produced gases of heavy oil in situ recovery processes using aqueous extraction - Google Patents

Abstract

A method for carbon dioxide removal, and optionally additionally hydrogen sulfide removal, from produced gas in heavy oil in situ (HOIS) recovery processes using the produced water may comprise: performing the HOIS recovery process on a heavy oil to yield water, heavy oil, fines, and produced gas, wherein the produced gas comprises light hydrocarbons, carbon dioxide, and optionally hydrogen sulfide; separating the produced gas from the water, the heavy oil, and the fines; compressing the produced gas to yield a compressed produced gas; mixing the compressed produced gas with an absorption water to yield a mixture; cooling the mixture to yield a cooled mixture; separating the cooled mixture into (a) a carbonated water stream comprising the carbon dioxide and optionally the hydrogen sulfide dissolved in the absorption water each at a higher concentration than in the absorption water and (b) one or more hydrocarbon streams.

Description

CARBON DIOXIDE REMOVAL FROM PRODUCED GASES OF
HEAVY OIL IN SITU RECOVERY PROCESSES USING AQUEOUS
EXTRACTION
FIELD OF INVENTION
[0001] The present disclosure relates to carbon dioxide removal from produced gas in heavy oil in situ (HOIS) recovery processes and potential sequestration of said carbon dioxide.
BACKGROUND
100021 This section is intended to introduce various aspects of the art that may be associated with the present disclosure. This discussion aims to provide a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as an admission of prior art.
[0003] Recovery of heavy oil from reservoirs can be performed by in situ recovery processes (referred to herein generally as heavy oil in situ (HOIS) recovery processes) with steam like cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), and steam-flood (SF). Generally, in these processes steam is injected into a heavy oil reservoir, which increases the temperature so as to lower the viscosity of oil allowing it to flow and be produced. Said processes have been used for recovering hydrocarbons from oil sands and bitumen reserves.
[0004] The material produced from HOIS recovery processes include water, liquid hydrocarbons, fines, and produced gas. The source of the produced gas includes (1) the carbon dioxide (CO2), hydrogen sulfide (H25), and now gas phase hydrocarbons native to the reservoir and (2) the reaction products between said gases and the steam. The produced gas typically has varying amounts of carbon dioxide (CO2) and hydrogen sulfide (H2S). Typically, produced gas has about 25 mol% to about 60 mol% CO2 and about 0.2 mol% to about 0.3 mol% H2S from the reservoir. The remainder of the produced gas is primarily hydrocarbons of which about 50 mol% is methane.

=
[0005] At the surface, the produced gas is separated from the other components and optionally treated to reduce the amount of sulfur. At least a portion of the produced gas, sulfur treated or not, is then sent to a boiler as fuel gas. Prior to the boilers, oftentimes the produced gas is mixed with a sweet gas stream (i.e., a stream having a low sulfur content like a low-sulfur methane stream) to provide additional heating capacity to the boiler. In the boiler, the produced gas is used as fuel gas to generate the steam from the water that is recycled back into the HOIS recovery process. The combustion products arising from the combustion of the fuel gas in the boiler is referred to as a flue gas.
[0006] In said processes, the CO2 is present throughout the processing of the produced gas and combusting of the fuel gas. For example, the flue gas typically has about 8 mol% to about 10 mol% CO2. The flue gas may contain some sulfur oxides (S0x) if H2S
treatment is not performed or is inefficient upstream of the boiler (e.g., with a sulfur recovery unit).
However, CO2, H2S, and SOx have no heating value in the combustion process and essentially act as a diluent to the combustible gases reducing the overall heating value per volume.
SUMMARY OF INVENTION
[0007] The present disclosure relates to carbon dioxide removal from produced gas in HOIS recovery processes using the produced water and potential sequestration of said carbon dioxide via absorption of the carbon dioxide into the produced water and sequestering the carbon dioxide enriched stream into a subterranean formation. In embodiments, the produced gas may additionally include hydrogen sulfide, which may additionally be absorbed into the produced water prior to sequestering the carbon dioxide enriched stream into the subterranean formation In other embodiments, this disclosure relates to removing carbon dioxide, and optionally additionally hydrogen sulfide, from the produced gas before using the produced gas as fuel gas in a boiler.
[0008] A non-limiting example method of the present disclosure comprises: performing a heavy oil in situ recovery process on a heavy oil to yield water, heavy oil, fines, and produced gas, wherein the produced comprises light hydrocarbons, carbon dioxide, and optionally hydrogen sulfide; separating the produced gas from the water, the heavy oil, and the fines;
compressing the produced gas to yield a compressed produced gas; mixing the compressed

- 2 -=
produced gas with an absorption water to yield a mixture; cooling the mixture to yield a cooled mixture; separating the cooled mixture into (a) a carbonated water stream comprising the carbon dioxide and optionally the hydrogen sulfide dissolved in the absorption water each at a higher concentration than in the absorption water and (b) one or more hydrocarbon streams.
[0009] A non-limiting example system of the present disclosure comprises: a compression subsystem configured to receive a produced gas stream and produce a compressed produced gas stream; a mixing subsystem configured to receive the compressed produced gas stream from the compression subsystem, mix the compressed produced gas stream with an absorption water stream, and produce a mixture stream; a cooling subsystem configured to receive the mixture stream from the mixing subsystem, cool the mixture stream, and produce a cooled mixture stream; and a separation subsystem configured to receive the cooled mixture stream from the cooling subsystem, separate the cooled mixture into one or more hydrocarbon streams and a carbonated water stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] The following figures are included to illustrate certain aspects of the embodiments, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.
[0011] FIG. lA illustrates a flow diagram of a non-limiting example method of the present disclosure.
[0012] FIG. 1B illustrates a non-limiting example method of performing the step of compressing the produced gas to yield the compressed process gas.
[0013] FIG. 2 is flow diagram of a non-limiting example system of the present disclosure.
[0014] FIGS. 3 and 4 are plots of the concentration H25 and CO2 (respectively) that is absorbed in water as a function of the pressure of said gas at a variety of temperatures.
DETAILED DESCRIPTION
[0015] The present disclosure relates to carbon dioxide capture from produced gas in HOIS recovery processes. More particularly, this disclosure relates to removing carbon

- 3 -dioxide from the produced gas before using the produced gas as fuel gas in a boiler. In embodiments, the removed carbon dioxide is sequestered by injecting the carbon dioxide enriched stream into a subterranean formation.
[0016] As described above, the inclusion of CO2 and H2S in fuel gas in HOIS recovery processes is inefficient because said gases have little to no heating value in the combustion process and essentially act as a diluent to the combustible gases. For example, the inclusion of CO2 and H2S in such fuel gases brings down the quality of the steam generated at the boilers about 70% vapor or less due to burning this type of low BTU gas.
[0017] The present disclosure reduces or, in some instances, removes the CO2 and H2S
from the produced gas before sending the light hydrocarbons in the produced gas to the boiler.
Therefore, the heating value of the fuel gas of the methods and systems described herein is greater. Without being limited by theory, it is believed that the higher heating value fuel gases described herein can improve boiler efficiency to 75% or more vapor steam quality.
[0018] Briefly, the methods and systems described herein dissolve the CO2 and H2S in water, which can be readily separated from the light hydrocarbons. Then, the separated light hydrocarbons can be used as fuel gas. Further, the water having CO2 dissolved therein can, advantageously, be injected into a sequestration well for CO2 capture.
[0019] Additionally, many HOIS recovery processes produce caustic water that has to be further processed before it can be released into the environment. The methods and systems described herein can utilize said caustic water for adjusting the pH
throughout the process, which further reduces waste and expensive treatment operations, and improves the carbon dioxide absorption efficiency of the system and associated processes herein.
Definitions and Test Methods [0020] Unless otherwise indicated, room temperature is defined herein as 25 C.
[0021] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a range from 1 to 9 (or CI -C9).
[0022] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil"
includes bitumen.
Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API gravity

- 4 -between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.00 API (density of 1,000 kg/m3 or 1 g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.
[0023] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of: 19 wt% percent (%) aliphatics (which can range from 5 wt% to 30 wt% or higher);
19 wt%
asphaltenes (which can range from 5 wt% to 30 wt% or higher); 30 wt% aromatics (which can range from 15 wt% to 50 wt% or higher); 32 wt% resins (which can range from 15 wt% to 50 wt% or higher); and some amount of sulfur (which can range in excess of 7 wt%), based on the total bitumen weight. In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt% to in excess of 0.7 wt%. The percentage of the hydrocarbon found in bitumen can vary.
[0024] The term "produced gas" as used herein refers to a mixture comprising primarily methane, but including other components such as hydrogen sulfide and carbon dioxide, that is recoverable through a well from an underground reservoir and that is in a gaseous state at standard pressure and temperature conditions (1 atmosphere and 60 F) at the wellhead.
[0025] The term "flue gas" as used herein refers to the combustion products arising from the combustion of the hydrocarbons in the boiler as described herein.
[0026] As used herein, a reference to a "C." fraction, stream, portion, feed, or other quantity is defined as a fraction (or other quantity) where 50 mol% or more of the fraction corresponds to hydrocarbons having "x" number of carbons. When a range is specified, such as "C.-Cy," 50 mol% or more of the fraction corresponds cumulatively to hydrocarbons having a number of carbons from "x" to "y" but does not necessarily mean that each carbon number x-y are present. A specification of "C.+" (or "C._") corresponds to a fraction where 50 mol%

- 5 -or more of the fraction corresponds cumulatively to hydrocarbons having the specified number of carbons or more (or the specified number of carbons or less) but does not necessarily mean that each carbon number x+ (or x-) are present.
[0027] "Steam quality" is measured by the mass fraction of a cold water stream that is converted into a vapor. For example, an 80% quality steam has around 80 wt% of the feed water converted to vapor.
Methods and Systems [0028] Generally, the methods and systems described herein compress produced gas from a HOTS recovery process and cool the compressed produced gas in an absorption water to dissolve the CO2 and H2S in the absorption water. The resultant carbonated water is then separated from the light hydrocarbons that were present in the produced gas.
The light hydrocarbons are then a higher BTU fuel that can be used in the boiler, and the carbonated water can be sequestered in a subterranean formation (e.g., a sandstone formation) for CO2 capture.
[0029] As described above HOTS recovery processes generally include injecting steam into a heavy oil reservoir to yield water, heavy oil, fines, and produced gas.
Known methods can be used to separate these products and yield a produced gas stream for use in the methods described herein. The produced gas stream typically comprises light hydrocarbons, carbon dioxide, and hydrogen sulfide (when present).
[0030] Examples of HOTS recovery processes are described in US Patent App.
Pub. No.
2015/0107833 and US Patent Nos. 5,238,066, 6,289,988, 6,540,023, 7,294,156, and 8,770,288, which are incorporated herein by reference.
[0031] Optionally, in the methods and systems described herein, the produced gas stream can be treated to remove or reduce the concentration of hydrogen sulfide in the produced gas stream before combining the produced gas stream (or a compressed version thereof) with absorption water.
[0032] The produced gas stream used in the methods and systems described herein may be from a single HOIS recovery process. Alternatively, the produced gas stream used in the methods and systems described herein may be a mixture of produced gas streams from two or

- 6 -=
more HOIS recovery processes (which may be the same or different methods for HOIS
recovery).
[0033] As will be apparent to those skilled in the art, systems and methods described herein (generally or relative to a specific figure) may include additional components like compressors, membranes, valves, flow meters, heat exchangers, traps, and the like for proper and safe operation of said systems and methods.
[0034] FIG. 1A illustrates a flow diagram of a non-limiting example method 100 of the present disclosure. A produced gas 102 from one or more HOIS recovery processes is compressed 104 (e.g., in one or multiple stages) to yield a compressed process gas 106 (which may be in a dense gas phase and/or a liquid phase).
[0035] The compressed process gas 106 is then mixed 110 with absorption water 108 to yield a mixture 112. The compressed process gas 106 may be at a pressure of about 6 MPa to about 20 MPa (or about 6 MPa to about 15 MPa, or about 12 MPa to about 19 MPa, or about 13 MPa to about 17 MPa) before mixing with the absorption water 108.
[0036] The absorption water 108 may have a temperature of about 50 C to about 90 C
(about 60 C to about 85 C, or about 65 C to about 75 C) before mixing with the compressed process gas 106.
[0037] The absorption water 108 may have a dissolved solids content of about 1,000 ppm to 25,000 ppm (or about 5,000 ppm to about 20,000 ppm, or about 10,000 ppm to about 15,000 ppm) before mixing with the compressed process gas 106.
[0038] The absorption water 108 may have a pH of about 4 to about 8 (or about 5 to about

7) before mixing with the compressed process gas 106.
[0039] The source of the absorption water 108 may be a nearby water source (e.g., a lake, a stream, or the like), a water effluent stream from the HOIS recovery process, brakish water, supernatant water, or any other source readily available. Generally, the HOIS
recover process produces significant amounts of water effluent. Therefore, said water effluent streams may advantageously be used in the methods and systems described herein. While not shown in the figure, the heavy oil in situ recovery processes can contain separation systems for separating water from the fluids produced from the heavy oil in situ recovery process which may be utilized as the water effluent stream in the processes described herein.
Without being limited by theory, it is believed that increased dissolved solids (e.g., salinity) will reduce the absorption capacity for the CO2 and H2S.
[0040] The mixture 112 is then cooled 114 to yield a cooled mixture 116.
The higher the pressure and lower the temperature of the cooled mixture 116, the more CO2 and H2S that can be dissolved in the absorption water 108. However, because light hydrocarbons are present, the temperature and pressure should be chosen to mitigate the formation of gas hydrates. Gas hydrates are ice-like crystalline structures produced when low molecular weight gases like methane, ethane, and carbon dioxide combine with water and freeze. These gas hydrates can form on walls and internal elements of piping systems and result in plugging or excessive pressure drops in the piping systems and associated equipment. Additionally, when gas hydrates dissociate suddenly, the low molecular weight gas expands quickly and can cause excessive pressure excursions.
[0041] The cooled mixture 116 may be at a pressure of about 10 MPa to about 20 MPa (or about 12 MPa to about 19 MPa, or about 13 MPa to about 17 MPa) and a temperature of about 10 C to about 40 C (about 15 C to about 35 C, or about 20 C to about 30 C). While both temperature and pressure effect the formation of gas hydrates, preferably the temperature is above about 15 C and more preferably above about 20 C to mitigate gas hydrate formation.
[0042] The cooled mixture 116 is then separated 118 into (a) a carbonated water stream 120 comprising the carbon dioxide and optionally the hydrogen sulfide dissolved in the absorption water each at a higher concentration than in the absorption water and (b) one or more hydrocarbon streams 122. The one or more hydrocarbon stream 122 may include a hydrocarbon gas stream 122a and a hydrocarbon liquid stream 122b.
[0043] Separating 118 the cooled mixture 116 can be performed by any known method including flashing, column separation, and the like.
[0044] The carbonated water stream 120 can be injected 124 into a subterranean formation for sequestration of the absorbed CO2. Generally, for sequestration, the absorption water should have a pH of about 3.5 or greater (or preferably about 3.5 to about 6, or about 5.5 to about 6.5). The carbonated water stream 120 may have a pH of about 3.5 or greater (or preferably about 3.5 to about 6, or about 5.5 to about 6.5). The pH of the cooled mixture 116 may be adjusted before separating 118 to achieve a desired pH (e.g., a pH
suitable for

- 8 -sequestration). The pH of the cooled mixture 116 may be adjusted with caustic water that is a byproduct or waste stream of a HOIS recovery process, which would advantageously reduce the waste from and/or resources necessary to remediate such a caustic stream.
[0045] Depending on the separation conditions the hydrocarbon gas stream 122a may comprise 50 mol% or greater (or 50 mol% to 100 mol%, or 60 mol% to 99 mol%, or 75 mol%
to 99 mol%) methane or may comprise 50 mol% or greater (or 50 mol% to 100 mol%, or 60 mol% to 99 mol%, or 75 mol% to 99 mol%) cumulatively of C1-2. Depending on the separation conditions the hydrocarbon liquid stream 122b may comprise 50 mol% or greater (or 50 mol%
to 100 mol%, or 60 mol% to 99 mol%, or 75 mol% to 99 mol%) cumulatively of C2-

9 or may comprise 50 mol% or greater (or 50 mol% to 100 mol%, or 60 mol% to 99 mol%, or 75 mol%
to 99 mol%) cumulatively of C3-9.
[0046] At least a portion of the hydrocarbon gas stream 122a may be combusted 124 in the boiler in a HOIS recovery process.
[0047] At least a portion of the hydrocarbon liquid stream 122b may be combusted 126 in the boiler in a HOIS recovery process. Alternative to or in combination with the foregoing, at least a portion of the hydrocarbon liquid stream 122b may be used 126' as a diluent for a heavy oil produced in a HOIS recovery process. Alternative to or in combination with one or both of the foregoing, at least a portion of the hydrocarbon liquid stream 122b may be separated 126" into a first hydrocarbon stream 128 (e.g., comprising C2-4 hydrocarbons or C3-4 hydrocarbons or C3-5 hydrocarbons) that may be combusted 132 in the boiler in a HOIS
recovery process and a second hydrocarbon stream 130 (e.g., comprising C5-9 hydrocarbons or C6-9 hydrocarbons) that may be used 134 as a diluent for a heavy oil produced in a HOIS
recovery process.
[0048] FIG. 1B illustrates a non-limiting example method 101 of performing the step of compressing 104a the produced gas 102 from one or more HOIS recovery processes to yield the compressed process gas 106a. The steps in FIG. 1B are optional and not required. The method described in FIG. 1A can simply be performed by compressing 104 (single stage or multi-stage) the produced gas 102 to yield the compressed process gas 106.
[0049] As illustrated in FIG. 1B, the concept of dissolving the CO2 and/or H2S is implemented in series with the stages of a multi-stage compression. The produced gas 102 (again from one or more HOIS recovery processes) may undergo a first stage of compression 104a to yield a first compressed produced gas 106a (e.g., to a pressure of about 0.5 MPa to about 2 MPa). The first compressed produced gas 106a is mixed 152 with caustic water 150 to yield a mixture 154. Caustic water 150 having a pH of about 8 to about 12 is used because as pH increases, the maximum dissolved CO2 concentration increase. The mixture 154 is then separated 156 into second compressed produced gas 106b and spent caustic water 158. The spent caustic water 158 can be mixed 160 with the cooled mixture 116 and/or carbonated water stream 120 of FIG. 1A, or alternatively the spent caustic water 158 can be sequestered via injection into a subterranean formation. While not shown in the figure, the heavy oil in situ recovery processes can contain caustic treating systems for treating fluids produced from the heavy oil in situ recovery process and/or for treating water used in the associated post-recovery processes which produce caustic containing streams which may be utilized as the caustic water or spent caustic water streams in the processes described herein. In embodiments, these caustic streams may contain sodium hydroxide and/or calcium hydroxide.
[0050] The second compressed produced gas 106b can be further compressed 104b (e.g., to a pressure of about 3 MPa to about 10 MPa), which may cause additional spent caustic water to condense and be separated 156a into third compressed produced gas 106c and second spent caustic water 158a. The second spent caustic water 158a can be mixed 160a with the cooled mixture 116 and/or carbonated water stream 120 of FIG. 1A. This process of compressing and removing condensing spent caustic water from the resultant compressed produced gas can be performed as many times as desired (shown by element 106n).
[0051] While not illustrated in FIGS. 1A and 1B, the compressing and condensing of the produced gas may also allow for separating C2-9 hydrocarbons or C3-9 hydrocarbons from the produced gas, which can be mixed with or treated like the hydrocarbon liquid stream 122b of FIG. 1A.
[0052] The systems of the present disclosure generally include a compression subsystem configured to receive a produced gas stream and produce a compressed produced gas stream.
The compression subsystem may include one or more compressors, optionally one or more separation units (e.g., flash drums), and optionally one or more heat exchange units.

- 10 -[0053] The systems also include a mixing subsystem configured to receive the compressed produced gas stream from the compression subsystem, mix the compressed produced gas stream with an absorption water stream, and produce a mixture stream. The mixing subsystem may include one or more mixers that entrain the produced gas stream with the absorption water stream. Alternatively, the mixing subsystem may be lines with corresponding valves that entrain the produced gas stream with the absorption water stream.
[0054] The systems also include a cooling subsystem configured to receive the mixture stream from the mixing subsystem, cool the mixture stream, and produce a cooled mixture stream. The cooling subsystem may include heat exchangers.
[0055] The systems also include a separation subsystem configured to receive the cooled mixture stream from the cooling subsystem (and optionally receive streams from the compression subsystem when separators and caustic streams are used in series with compressors), separate the cooled mixture into one or more hydrocarbon streams and a carbonated water stream. The separation subsystem may comprise one or more flash drums and/or one or more column separators.
[0056] FIG. 2 is flow diagram of a non-limiting example system 200 of the present disclosure illustrating the processes and systems herein with multiple wells and associated produced gas streams.
[0057] The system 200 includes produced gas stream 202a, 202b, and 202c from three HOIS recovery processes. First-stage compressors 204a, 204b, and 204c are configured to receive and compress the produced gas stream 202a, 202b, and 202c, respectively, and produce first compressed produced gas streams 206a, 206b, and 206c, respectively. While this example illustrates produced gas streams from three (3) HOIS recovery processes, such disclosure is not limited as such but may be performed with any number of separate HOIS
recovery processes.
[0058] A first vessel 208 is configured to receive the first compressed produced gas streams 206a, 206b, and 206c. As illustrated, the first compressed produced gas streams 206a, 206b, and 206c are mixed before introduction to the first vessel 208. However, each may be introduced to the first vessel 208 separately.

- 11 -[0059] The first vessel 208 may optionally also be configured to receive a caustic stream 210. When a caustic stream 210 is also implemented, the caustic stream 210 and first compressed produced gas streams 206a, 206b, and 206c mix where a portion of the CO2 in the first compressed produced gas streams 206a, 206b, and 206c dissolves in the water of the caustic stream. In the first vessel 208, the liquid is removed as spent caustic stream 212 and the gas is removed as second compressed production gas stream 214.
[0060] When the caustic stream 210 is not implemented, the first vessel collects any condensed fluid, which are removed as a condensate stream (not illustrated).
[0061] A second-stage compressor 216 is configured to receive the second compressed production gas stream 214, compress the second compressed production gas stream 214, and produce a third compressed production gas stream 218.
[0062] A second vessel 220 is configured to receive the third compressed production gas stream 218, separate the gas from the condensed liquid, and produce a fourth compressed production gas stream 224 and a second spent caustic stream 222 when the caustic stream is implemented (or a second condensate stream, not illustrated, when the caustic stream is not implemented).
[0063] A third-stage compressor 226 is configured to receive the fourth compressed production gas stream 224, compress the fourth compressed production gas stream 224, and produce a fifth compressed production gas stream 228.
[0064] In the illustrated system 200, the fifth compressed production gas stream 228 is configured to receive or combine with an absorption water stream 230 to produce a mixture stream. However, a vessel or other mixing apparatus may be implemented.
[0065] A heat exchanger 234 is configured to receive the mixture stream 232, cool the mixture stream 232, and produce a cooled mixture stream 236. While the system 200 includes .. only one heat exchanger, more than one may be implemented.
[0066] Optionally, the cooled mixture stream 236 may be configured to receive a second caustic stream 238 for adjusting the pH of the cooled mixture stream 236.
[0067] A separator 240 is configured to receive the cooled mixture stream 236 (whether pH adjusted or not), optionally the spent caustic stream 212, and optionally the second spent caustic stream 222. In the separator 240, the hydrocarbon gas, hydrocarbon liquid, and

- 12 -carbonated water separate to form a hydrocarbon gas stream 242, a hydrocarbon liquid stream 244, and a carbonated water stream 246. In embodiments, the carbonated water stream 246 can be sequestered via injection into a subterranean formation.
[0068] The hydrocarbon gas stream 242 may optionally be used as the cooling gas in the heat exchanger 234 or other heat exchanger in the system 200.
[0069] The system 200 may optionally further include a second separator 248 configured to receive the hydrocarbon liquid stream 244 and produce a first hydrocarbon stream 250 and a second hydrocarbon stream 252.
[0070] The streams from the separator 240 and optionally the second separator 248 may be further conveyed as described in FIG. 1A.
Example Embodiments [0071] A first non-limiting example embodiment of the present disclosure is a method comprising: performing a heavy oil in situ recovery process on a heavy oil to yield water, heavy oil, fines, and produced gas, wherein the produced gas comprises light hydrocarbons, and carbon dioxide; separating the produced gas from the water, the heavy oil, and the fines;
compressing the produced gas to yield a compressed produced gas; mixing the compressed produced gas with an absorption water to yield a mixture; cooling the mixture to yield a cooled mixture; separating the cooled mixture into (a) a carbonated water stream comprising at least a portion of the carbon dioxide dissolved in the absorption water each at a higher concentration than in the absorption water and (b) one or more hydrocarbon streams. The first non-limiting example embodiment may further include one or more of: Element 1: the method wherein the produced gas further comprises hydrogen sulfide; Element 2: Element 2 and wherein at least a portion of the hydrogen sulfide is dissolved in the adsorption water;
Element 3: the method further comprising: sequestering the carbonated water stream in a subterranean formation;
Element 4: wherein the compressed produced gas has a pressure of about 6 MPa to about 20 MPa; Element 5: wherein cooling the mixture is to a temperature of about 10 C
to about 40 C;
Element 6: wherein cooling the mixture is to a temperature of about 20 C to about 30 C;
Element 7: the method further comprising: combusting at least a portion of each of the one or more hydrocarbon streams in a boiler to yield steam for the heavy oil in situ recovery process;
Element 8: the method further comprising: wherein the one or more hydrocarbon streams

- 13 -include (i) a C2-9 hydrocarbons stream and (ii) a methane stream: Element 9:
Element 8 and the method further comprising: combusting at least a portion of the methane stream in a boiler to yield steam for the heavy oil in situ recovery process; Element 10: Element 8 and the method further comprising: separating at least a portion of the C2-9 hydrocarbons stream to a C24 hydrocarbon stream and a C5-9 hydrocarbon stream; and combusting at least a portion of the C24 hydrocarbon stream in a boiler to yield steam for the heavy oil in situ recovery process;
Element 11: Element 10 and the method further comprising: using the C5-9 hydrocarbons stream as a diluent for transporting the heavy oil; Element 12: Element 10 and the method further comprising: using the C5-9 hydrocarbons stream as a diluent in the heavy oil in situ recovery process; Element 13: wherein the carbonated water stream has a pH of about 3.5 or greater; Element 14: the method further comprising: mixing the production gas and/or the compressed production gas with caustic water before mixing with the absorption water;
Element 15: the method further comprising: mixing the mixture with caustic water before separating the mixture; and Element 16: wherein the produced gas is a mixture of two or more produced gas streams from separate heavy oil in situ recovery processes.
Examples of combinations include, but are not limited to, two or more of Elements 1-6 in combination; one or more of Elements 1-6 in combination with Element 7 and optionally in further combination with one or more of Elements 13-16; Element 7 and in combination with one or more of Elements 13-16; one or more of Elements 1-6 in combination with Element 8 (optionally in combination with one or more of Elements 9-10) and optionally in further combination with one or more of Elements 13-16; Element 8 (optionally in combination with one or more of Elements 9-10) and in combination with one or more of Elements 13-16; and one or more of Elements 1-6 in combination one or more of Elements 13-16.
[0072] A second non-limiting example embodiment (Element 18) of the present disclosure is a system comprising: a compression subsystem configured to receive a produced gas stream from one or more heavy oil in situ recovery process systems and produce a compressed produced gas stream; a mixing subsystem configured to receive the compressed produced gas stream from the compression subsystem, mix the compressed produced gas stream with an absorption water stream, and produce a mixture stream; a cooling subsystem configured to receive the mixture stream from the mixing subsystem, cool the mixture stream,

- 14 -=
and produce a cooled mixture stream; and a separation subsystem configured to receive the cooled mixture stream from the cooling subsystem, separate the cooled mixture stream into one or more hydrocarbon streams and a carbonated water stream. The second non-limiting example embodiment (Element 18) may further include one or more of: Element 19: the system of Element 18, comprising more than one heavy oil in situ recovery process systems each producing a portion of the produced gas; Element 20: the system of Element 19, wherein each of the heavy oil in situ recovery process systems comprises a compressor;
Element 21:
the system of any one of Elements 18-20, further comprising a system for removing water recovered from the one or more heavy oil in situ recovery process systems and using at least a portion of this water as the adsorption water stream; Element 22: the system of any one of Elements 18-21, further comprising a caustic system for producing a caustic water and using at least a portion of the caustic water as the adsorption water stream;
Element 23: the system of Element 22, configured to inject the caustic water into a first separation vessel where it contacts the cooled mixture stream; Element 24: the system of Element 23, configured with a compressor to compress the one or more hydrocarbon streams to form a second compressed gas and a second separation vessel to separate a spent caustic water stream from the second compressed gas and a piping system to return at least a portion of the spent caustic water stream to the first separation vessel; Element 25: the system of any one of Elements 18-24, comprising a boiler configured to receive at least a portion of the one or more hydrocarbon streams as a fuel gas; and Element 26: The system of any one of Elements 18-25, comprising an injection system to receive at least a portion of the carbonated water stream and inject the carbonated water stream into an underground formation.
[0073] Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the present specification and associated claims are to be understood as being modified in all instances by the term "about." Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by the embodiments of the present invention. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claim, each numerical parameter should at least be

- 15 -construed in light of the number of reported significant digits and by applying ordinary rounding techniques.
[0074] One or more illustrative embodiments incorporating the invention embodiments disclosed herein are presented herein. Not all features of a physical implementation are described or shown in this application for the sake of clarity. It is understood that in the development of a physical embodiment incorporating the embodiments of the present invention, numerous implementation-specific decisions must be made to achieve the developer's goals, such as compliance with system-related, business-related, government-related and other constraints, which vary by implementation and from time to time. While a developer's efforts might be time-consuming, such efforts would be, nevertheless, a routine undertaking for those of ordinary skill in the art and having benefit of this disclosure.
[0075] While compositions and methods are described herein in terms of "comprising"
various components or steps, the compositions and methods can also "consist essentially of' or "consist of' the various components and steps.
[0076] To facilitate a better understanding of the embodiments of the present invention, the following examples of preferred or representative embodiments are given.
In no way should the following examples be read to limit, or to define, the scope of the invention.
EXAMPLES
[0077] FIGS. 3 and 4 are plots of the concentration H2S and CO2 (respectively) that is absorbed in water as a function of the pressure of said gas at a variety of temperatures. Data was collected using water having a pH of about 7, about 12,000 ppm total dissolved solids, and about 200 ppm alkalinity. FIGS. 3 and 4 illustrate that as pressure increases and temperature decreases, the concentration of H2S and CO2 that can be absorbed in water increases.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular

- 16 -illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of "comprising," "containing,"
or "including" various components or steps, the compositions and methods can also "consist essentially of' or "consist of' the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, "from about a to about b," or, equivalently, "from approximately a to b," or, equivalently, "from approximately a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite .. articles "a" or "an," as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

- 17 -

Claims (26)

CLAIMS:

1. A method comprising:
performing a heavy oil in situ recovery process on a heavy oil to yield water, heavy oil, fines, and produced gas, wherein the produced gas comprises light hydrocarbons, and carbon dioxide;
separating the produced gas from the water, the heavy oil, and the fines;
compressing the produced gas to yield a compressed produced gas;
mixing the compressed produced gas with an absorption water to yield a mixture;
cooling the mixture to yield a cooled mixture;
separating the cooled mixture into (a) a carbonated water stream comprising at least a portion of the carbon dioxide dissolved in the absorption water at a higher concentration than in the absorption water and (b) one or more hydrocarbon streams.

2. The method of claim 1, wherein the produced gas further comprises hydrogen sulfide.

3. The method of claim 2, wherein at least a portion of the hydrogen sulfide is dissolved in the adsorption water.

4. The method of any one of claims 1 to 3, further comprising:
sequestering at least a portion of the carbonated water stream in a subterranean formation.

5. The method of any one of claims 1 to 4, wherein the compressed produced gas has a pressure of about 6 MPa to about 20 MPa.

6. The method of any one of claims 1 to 5, wherein cooling the mixture is to a temperature of about 10°C to about 40°C.

7. The method of any one of claims 1 to 6, wherein cooling the mixture is to a temperature of about 20°C to about 30°C.

8. The method of any one of claims 1 to 7, further comprising:
combusting at least a portion of each of the one or more hydrocarbon streams in a boiler to yield steam for the heavy oil in situ recovery process.

9. The method of any one of claims 1 to 7, wherein the one or more hydrocarbon streams include (i) a C2-9 hydrocarbons stream and (ii) a methane stream.

10. The method of claim 9, further comprising:
combusting at least a portion of the methane stream in a boiler to yield steam for the heavy oil in situ recovery process.

11. The method of claim 9, further comprising:
separating at least a portion of the C2-9 hydrocarbons stream to a C2-4 hydrocarbon stream and a C5-9 hydrocarbon stream; and combusting at least a portion of the C2-4 hydrocarbon stream in a boiler to yield steam for the heavy oil in situ recovery process.

12. The method of claim 11, further comprising:
using the C5-9 hydrocarbons stream as a diluent for transporting the heavy oil.

13. The method of claim 11, further comprising:
using the C5-9 hydrocarbons stream as a diluent in the heavy oil in situ recovery process.

14. The method of any one of claims 1 to 13, wherein the carbonated water stream has a pH of 3.5 or greater.

15. The method of any one of claims 1 to 14, further comprising:
mixing the production gas and/or the compressed production gas with caustic water before mixing with the absorption water.

16. The method of any one of claims 1 to 15, further comprising:
mixing the mixture with caustic water before separating the mixture.

17. The method of any one of claims 1 to 16, wherein the produced gas is a mixture of two or more produced gas streams from separate heavy oil in situ recovery processes.

18. A system comprising:
a compression subsystem configured to receive a produced gas stream from one or more heavy oil in situ recovery process systems and produce a compressed produced gas stream;
a mixing subsystem configured to receive the compressed produced gas stream from the compression subsystem, mix the compressed produced gas stream with an absorption water stream, and produce a mixture stream;
a cooling subsystem configured to receive the mixture stream from the mixing subsystem, cool the mixture stream, and produce a cooled mixture stream; and a separation subsystem configured to receive the cooled mixture stream from the cooling subsystem, separate the cooled mixture stream into one or more hydrocarbon streams and a carbonated water stream.

19. The system of claim 18, comprising more than one heavy oil in situ recovery process systems, each producing a portion of the produced gas.

20. The system of claim 19, wherein each of the heavy oil in situ recovery process systems comprises a compressor.

21. The system of any one of claims 18 to 20, further comprising a system for removing water recovered from the one or more heavy oil in situ recovery process systems and using at least a portion of this water as the adsorption water stream.

22. The system of any one of claims 18 to 21, further comprising a caustic system for producing a caustic water and using at least a portion of the caustic water as the adsorption water stream.

23. The system of claim 22, configured to inject the caustic water into a first separation vessel where it contacts the cooled mixture stream.

24. The system of claim 23, configured with a compressor to compress the one or more hydrocarbon streams to form a second compressed gas and a second separation vessel to separate a spent caustic water stream from the second compressed gas and a piping system to return at least a portion of the spent caustic water stream to the first separation vessel.

25. The system of any one of claims 18 to 24, comprising a boiler configured to receive at least a portion of the one or more hydrocarbon streams as a fuel gas.

26. The system of any one of claims 18 to 25, comprising an injection system to receive at least a portion of the carbonated water stream and inject the carbonated water stream into an underground formation.