Method for generating or propagating carbon dioxide foam in a subterranean formation

Abstract

The present invention relates to a method for enhancing carbon dioxide foam generation and / or propagation in a subterranean formation, in particular for CO2-based enhanced oil recovery and / or CO2 sequestration applications.

Description

[0001] METHOD FOR GENERATING OR PROPAGATING CARBON DIOXIDE FOAM IN A SUBTERRANEAN FORMATION

[0002] TECHNICAL FIELD

[0003] The present invention relates to a method for generating and / or propagating carbon dioxide foam in a subterranean formation, in particular for CO2-based enhanced oil recovery and / or CO2 sequestration applications.

[0004] TECHNICAL BACKGROUND

[0005] Enhanced oil recovery (EOR) includes a variety of advanced methods employed to extract oil that remains unrecovered after primary and secondary recovery techniques. EOR often involves injecting a fluid into the underground reservoir (or subterranean formation) in order produce an additional quantity of hydrocarbons. The fluid which is used can be water, steam, carbon dioxide, natural gas, nitrogen, etc..

[0006] In particular, the injection of carbon dioxide (CO2), preferably in the supercritical state, provides a number of advantages. First, reservoir pressure is maintained. Second, oil viscosity is reduced: as carbon dioxide is miscible with oil, the oil expands and swells when put in contact with carbon dioxide. Third, oil displacement is improved because the interfacial tension between oil and water is reduced.

[0007] Furthermore, in light of growing concerns about climate change, CO2 EOR has emerged as a method to sequester CO2 underground (also known as longterm storage of anthropogenic carbon dioxide) while simultaneously producing oil with reduced CO2 emissions.

[0008] In CO2-based EOR and CO2 sequestration, CO2 has to displace residing water and / or oil. However, the injection of carbon dioxide into a formation (a porous medium, e.g., water-bearing subterranean formation such as an aquifer) is an unstable process due to the lower viscosity of carbon dioxide compared to water viscosity: carbon dioxide migrates away from the injection well, creating a carbon dioxide "plume" (volume occupied by gas, liquid or supercritical carbon dioxide undissolved in water) which can rise to the top parts of the formation due to the gravity override. The relatively low viscosity of carbon dioxide also causes viscous fingering and less effective displacement of water.

[0009] Moreover, in the presence of the cap rock / fault geomechanical defect, which creates a flow path, or in the absence of the capillary barrier, “free” CO2 can leak into the atmosphere due to the difference in density with respect to water. Therefore, reducing CO2 mobility is highly looked-for to stabilize the displacement front.

[0010] Mitigation of these issues can be achieved by the addition of a surfactant to generate CO2 foams. Generally, foams have a relatively high viscosity. Thus, the generation of such carbon dioxide foams makes it possible to strengthen the displacement front and increase the viscosity of the injected fluid. This enhances sweep efficiency and mobility control, which are crucial for maximizing hydrocarbon recovery or CO2 capacity storage.

[0011] Specifically, the viscous phase (carbon dioxide foam) replaces the low- viscosity phase (e.g., water present in the formation) by a “piston-like” mechanism which either increases / accelerates the carbon dioxide storage at a given injection zone (licensed area, exploitation zone) or reduces the extension of the carbon dioxide plume so as to remain far from some critical areas (such as areas with unsealing or reactivable faults, existing wells with integrity issue, etc.) or to stay within the storage limits, while ensuring that the geomechanical constraints due to the pressure increase during injection are respected.

[0012] Many surfactants have been reported in the literature, including for example cationic surfactants, nonionic surfactants and amine surfactants. In particular, W02018146107 and WO2024047372 describe the use of diamine surfactants in enhanced oil recovery and CO2 sequestration respectively.

[0013] However, the efficiency of CO2-based EOR or CO2 sequestration can be hindered by several challenges, notably the delay in foam generation and / or propagation through the formation. This delay, referred to as the Minimum Pore Volume (MPV), can primarily be attributed to the adsorption of surfactants onto the surfaces of the formation. Additionally, the delay in foam generation and propagation can result from the requirement of reaching the so-called Minimum Pressure Gradient (MPG), highly influenced by the characteristics, in particular the type and the morphology of the subterranean formation, thus playing a role in influencing the foam generation.

[0014] For such challenging environments, lower CO2 fraction relative to total injection volume can facilitate foam generation. However, in order to ensure efficient displacement of water and / or oil within the formation, it is essential to inject CO2 at higher fractions where the steady-state strength of the foam may be greater, i.e., the foam exhibits a high apparent viscosity, calculated from the pressure drop generated in the subterranean formation.

[0015] There is therefore a need to effectively control the MPV and PVP parameters by overcoming MPG and satisfying surfactant adsorption in order to enable rapid foam formation while ensuring the production of strong foam and swiftly achieving steady-state conditions.

[0016] SUMMARY OF THE INVENTION

[0017] The invention relates to a method for generating and / or propagating carbon dioxide foam in a subterranean formation, successively comprising at least the steps of: i) injecting into the subterranean formation at least an aqueous solution, a surfactant, and carbon dioxide at a fraction F1co2, ii) injecting into the subterranean formation, at least an aqueous solution, a surfactant and carbon dioxide at a fraction F2co2, wherein the carbon dioxide fraction F2co2 is higher than the carbon dioxide fraction F1 co2.

[0018] According to an embodiment, the surfactant in step i) and / or in step ii) is a compound of formula (I): wherein Ri, R2, R3, and R4 are independently a hydrogen atom or an alkyl group, A is an alkylene group, and the total number of carbon atoms in the surfactant compound of formula (I) is from 10 to 24.

[0019] Preferably, in formula (I), A comprises from 1 to 5 carbon atoms, preferably from 2 to 4 carbon atoms, and more preferably comprises 3 carbon atoms.

[0020] Preferably, at least one of R1, R2, R3 and R4 is an alkyl group comprising from 8 to 16 carbon atoms, preferably from 10 to 15 carbon atoms, and more preferably from 12 to 14 carbon atoms.

[0021] Preferably, A comprises 3 carbon atoms, R1 is an alkyl group comprising from 6 to 16 carbon atoms, R2 is a hydrogen atom, R3 is a methyl group and R4 is a methyl group.

[0022] Preferably, the compound of formula (I) is selected from N1 -dodecyl- N3,N3-dimethylpropane-1 ,3-diamine, N1-dodecyl-N1 ,N3,N3-trimethylpropane- 1 ,3-diamine, N1 -(2,2-diethyloctyl)-N3,N3-dimethylpropane-1 ,3-diamine, N1 -octyl- N3,N3-dimethylpropane-1 ,3-diamine, N1-decyl-N3,N3-dimethylpropane-1 ,3- diamine, N1 -tetradecyl-N3,N3-dimethylpropane-1 ,3-diamine, N1 -hexadecyl- N1 ,N3,N3-trimethylpropane-1 ,3-diamine, N1 -heptadecyl-N1 ,N3,N3- trimethylpropane-1 ,3-diamine, N1-octadecyl-N1 ,N3,N3-trimethylpropane-1 ,3- diamine, and N-dodecyl-1 ,3-propanediamine.

[0023] According to a preferred embodiment, the compound of formula (I) is N1 - dodecyl-N3,N3-dimethylpropane-1 ,3-diamine.

[0024] Preferably, the carbon dioxide is liquid or supercritical carbon dioxide.

[0025] Advantageously, the surfactant is included and / or dissolved in the aqueous solution, in the CO2 or in both.

[0026] Preferably, the aqueous solution is brine.

[0027] Preferably, the brine comprises one or more salts selected from alkali metal and alkaline earth metal chlorides, sulfates, nitrates, carbonates and bicarbonates.

[0028] Preferably, the brine has a salinity of from 70 to 350 g / L, preferably from 120 to 270 g / L.

[0029] According to an embodiment, the concentration of the surfactant in step i) or in step ii), is from 500 to 50,000 ppm, preferably from 1 ,000 to 20,000 ppm, more preferably from 1000 to 7,000 (w / v).

[0030] Preferably, the concentration of the surfactant injected in step i) is higher or equal than the concentration of the surfactant injected in step ii).

[0031] Preferably, the fraction of CO2 F1 co2 injected in step i) is at most 50%, preferably ranges from 5 % to 65%, preferably from 10% to 60%, more preferably, from 20% to 50%.

[0032] Preferably, the fraction of CO2 F2co2 injected in step ii) is 55% or higher, preferably between 70% and 99%, more preferably between 80 and 95%.

[0033] According to an embodiment, the aqueous solution, the surfactant and the CO2 injected in step i) and / or in step ii) are injected simultaneously.

[0034] According to an embodiment, step i) and / or step ii) include the sequential injection of the aqueous solution, the surfactant and the CO2.

[0035] According to an aspect, the CO2 foam according to the present invention is used for enhancing oil recovery from the subterranean formation.

[0036] Preferably, according to this aspect, the method further comprises a step iii) of recovering hydrocarbons from the subterranean formation.

[0037] According to another aspect, the CO2 foam according to the present invention the CO2 foam is used for CO2 sequestration into the subterranean formation. The method of the invention affords a more efficient carbon dioxide foam generation and / or propagation in a subterranean formation, especially in the context of EOR and / or CO2 sequestration.

[0038] In this method, the delay in foam generation may be mitigated through a preflush strategy. The MPV and parameters may be effectively controlled to enable rapid foam formation and the production of strong foam. This approach may accelerate foam generation, ensuring the rapid achievement of steady-state conditions in different types of subterranean formations and thus improving the mobility control of CO2.

[0039] BRIEF DESCRIPTION OF THE DRAWINGS

[0040] Figure 1 shows the different typical characteristics of transient foam behavior transport in a porous medium based on an experiment conducted on a quartz sandpack under 150 barg at 110°C, when conventionally injecting 95% volume fraction of CO2 and 2000 ppm of N1 -dodecyl-N3,N3-dimethylpropane-1 ,3- diamine as a surfactant in brine phase (5% volume fraction).

[0041] Figure 2 shows the impact of the method according to the present invention on foam generation on a quartz sandpack at 28°C (Figure 2a) and 110°C (Figure 2b). The x-axis represents the cumulative injection in pore volume (PV), and the y-axis represents the apparent viscosity in cP. The first injection at volume CO2 fraction (Fco2) 48% contains 5000 ppm of N1 -dodecyl-N3,N3- dimethylpropane-1 ,3-diamine as surfactant in brine phase (52% volume fraction). The second injection at 95% of CO2 contains 2000 ppm of N1 -dodecyl-N3,N3- dimethylpropane-1 ,3-diamine as surfactant in brine phase (5% volume fraction). The points define foam breakthrough time.

[0042] DESCRIPTION OF EMBODIMENTS

[0043] For the purpose of the present disclosure, the expression "between X and Y" includes the endpoints, unless explicitly stated otherwise. Therefore, this expression signifies that the intended range includes the values X, Y, and all values between X and Y.

[0044] For the purpose of the present disclosure, the terms “foam” and “emulsion” may be used interchangeably.

[0045] The cumulative volume of fluid injected into the subterranean formation may be expressed in a pore volume (PV) unit. This unit refers to the total volume of the injected fluid relative to the pore volume of the subterranean formation (or of a sample, in the case of an experimental demonstration of the method).

[0046] The pore volume of a sample of subterranean formation may be measured by a gas method or using a solution comprising a non-reactive agent. The pore volume of the subterranean formation may be calculated by the estimated area of the subterranean formation that could potentially be affected by the injected solution, and the thickness and porosity of the subterranean formation. For CO2-based EOR and CO2 sequestration applications, when injecting CO2, brine and surfactant (dissolved in one of two phases) into the formation, a delay in foam generation and development is often observed, known as Minimum Pore Volume (MPV).

[0047] During MPV, the pressure gradient rises gradually until it suddenly markedly increases (Figure 1 ), indicating the formation of a strong foam (or emulsion). The MPV is generally attributed to the time required for the pressure to reach a Minimum Pressure Gradient (MPG) that must be exceeded to start forming a strong foam, plus the time (related to the injected quantity of surfactant) necessary to satisfy surfactant adsorption on the formation.

[0048] Once foam starts to form, it propagates through the formation, which takes a certain amount of time (or volume of injected fluid), defined as the Pore Volume required for foam Propagation (PVP). During this time, the apparent viscosity continues to increase until it reaches a steady state plateau.

[0049] The sum of MPV and PVP is the number of pore volumes (PV) required for the foam to reach equilibrium (i.e., the plateau) and is defined here as EPV (Figure 1 ). The apparent viscosity at the plateau (PAV) is the steady-state foam force for a given injected CO2 volume fraction.

[0050] Besides, an important feature of the foam transport is its possible arrival before EPV, which implies that the foam texture continues to evolve in the formation. This is the sign that foam forms at the outlet due to the capillary end effect and that, once formed, it generates backwards against flow towards the inlet, resulting in an increase in apparent viscosity.

[0051] For some porous media, MPG increases with the CO2 volumetric fraction in the injected fluid, meaning that it is easier to generate the foam at a lower CO2 fraction, i.e., the pressure gradient to overcome is lower.

[0052] Therefore, for successful injection, MPV and PVP must be minimized by overcoming MPG and satisfying adsorption while ensuring a high apparent viscosity PAV at the highest possible CO2 fraction.

[0053] The present disclosure provides a method for generating and / or propagating carbon dioxide foam in a subterranean formation, successively comprising at least the steps of: i) injecting into the subterranean formation at least an aqueous solution, a surfactant, and carbon dioxide at a fraction F1co2, ii) injecting into the subterranean formation at least an aqueous solution, a surfactant and carbon dioxide at a fraction F2co2, wherein the carbon dioxide fraction F2co2 is higher than the carbon dioxide fraction F1 co2. The method according to the present disclosure results in accelerating the foam generation and / or propagation as compared to, for example, standard methods (for example for CO2-based EOR or CO2 sequestration) not including a pre-flushing step.

[0054] As used herein, the term “pre-flushing” a subterranean formation is intended to mean the implementation of step i) before the subsequent step ii) which is considered as the main operation (for example in the context of enhanced oil recovery and / or CO2 sequestration processes). Therefore, according to the invention, step i) is performed before step ii).

[0055] The applicant has found that the method according to the present disclosure makes it possible to reduce the MPV and PVP and thus ensures a rapid foam generation and / or propagation in the formation.

[0056] The method of the present disclosure is an improved method resulting in the generation of a strong foam having higher apparent viscosity and an efficient mobility control of CO2.

[0057] As used herein, a “strong foam” means a foam of high apparent viscosity.

[0058] According to an embodiment, when the method of the present disclosure is applied to an EOR process, it may provide improved sweep efficacy and thus increased oil recovery as compared to prior art methods of CO2-based EOR not including a pre-flushing step.

[0059] The term “sweep efficiency” refers to a measure of the effectiveness of an enhanced oil recovery process.

[0060] Subterranean formation

[0061] The subterranean formation according to the present disclosure can be an oil-bearing reservoir, in particular that has already undergone primary and secondary recovery methods.

[0062] The subterranean formation can also refer to a structure capable of longterm storing CO2, i .e. , having sufficient porosity and permeability for CO2 injection and storage. The subterranean formation capable of long-term storing CO2 may be a hydrocarbon-bearing reservoir or a formation that contains little or no hydrocarbons. In some embodiments, the subterranean formation may be a water-bearing formation, notably of clastic or carbonate nature, for example, an aquifer, in particular a saline aquifer.

[0063] The temperature within the subterranean formation may range from 5 to 140°C, 10 to 140°C, 20 to 140°C, 25 to 140°C, preferably from 60 to 140°C, more preferably from 80 to 140°C and even more preferably from 100 to 120°C. The permeability of at least a portion of the subterranean formation may range from 2 mD to 100 D, preferably from 5 mD to 40 D, more preferably from 5 mD to 5000 mD, preferably from 10 to 5000 mD, more preferably from 50 to 5000 mD, even more preferably from 100 to 5000 mD, and further more preferably from 500 to 5000 mD, as estimated by well log.

[0064] When the subterranean formation is a water-bearing formation, water within the formation may have a salinity of 0 to 300 g / L, preferably of 100 to 250 g / L, and more preferably of 150 to 200 g / L.

[0065] Salinity is defined herein as the total concentration of dissolved inorganic salts in water, including for example NaCI, CaCl2, MgCl2, Na2SO4, NaBr, NaNOs and any other inorganic salts.

[0066] Carbon dioxide

[0067] Preferably, the carbon dioxide used in the method according to the invention is either in a liquid or supercritical state when injected. As known to those skilled in the art, carbon dioxide is in a liquid phase at a pressure of approximately 1 ,000 psi and a temperature below 31 °C. When the temperature exceeds 31 °C at the same pressure, carbon dioxide transitions to a supercritical phase. The state of CO2, injected in the formation, whether it is liquid or supercritical, will thus be determined by the pressure and temperature conditions within the formation. Typically, the carbon dioxide to be injected into the formation according to the present disclosure is transported via a pipeline.

[0068] According to the present disclosure, the carbon dioxide fraction injected in step ii) is higher than the carbon dioxide fraction injected in step i).

[0069] For the purpose of the present invention, the term “carbon dioxide fraction” typically refers to the volume fraction of CO2. This fraction is calculated with respect to the total volume of the fluid injected into the formation, which includes all components such as CO2, the aqueous solution, the surfactant, and any other components or additives present in the injected slug.

[0070] Advantageously, the fraction of CO2 F1 C02 injected in step i) is at most 50%, preferably ranges from 5% to 65%, preferably from 10% to 60%, more preferably, from 20% to 50%.

[0071] Advantageously, in step ii), the carbon dioxide is injected at a fraction F2co2 of 55% or higher, preferably between 70% and 99%, more preferably between 80 and 95%.

[0072] Advantageously, the difference between F2co2 and F1 co2 is at least 5%, or at least 10%, or at least 15%, or at least 20%, or at least 25%, or at least 30%, or at least 35%, or at least 40%, or at least 50%, or at least 60%, or at least 70%. This difference may for example range from preferably from 30 to 60%,, preferably from 20 to 70%, more preferably from 10 to 80%, even more preferably from 5 to 94%

[0073] Those skilled in the art will understand that the CO2 fractions indicated herein correspond to the effective amounts of CO2 phase injected into the formation. Methods known in the art can be applied to adjust these fractions, accounting for differences between the pre-injection CO2 fraction and the actual CO2 fraction present in the formation, particularly due to interactions between CO2 and the aqueous solution, which include CO2 dissolution into the aqueous phase and the dissolution of water in CO2. CO2 dissolved in the aqueous phase is not included as part of the CO2 fractions defined above. The increase in the CO2 fraction between step i) and step ii) may be effected in a single increment, or in multiple increment, or in a gradual and continuous manner over a certain period of time.

[0074] In some embodiments, the carbon dioxide can be injected in step i) and / or in step ii) of the method according to the invention as a mixture comprising at least another gas such as nitrogen or methane.

[0075] Aqueous solution

[0076] Advantageously, the aqueous solution injected in step i) and / or ii) of the method according to the invention is an aqueous solution comprising at least water or brine.

[0077] It should be noted that the pH of the aqueous solution injected into the formation may be influenced by the presence of CO2. The pH must be such that the surfactant remains soluble in the aqueous solution.

[0078] According to some embodiments, the aqueous solution is a brine.

[0079] Typically, the brine is a highly concentrated solution of salts in water. The brine may be extracted from the subterranean formation, in particular from an aquifer or be artificially prepared. The aqueous solution may comprise or may be prepared from produced water or from sea water.

[0080] Preferably, the brine comprises one or more salts selected from alkali metal and alkaline earth metal chlorides, sulfates, nitrates, carbonates and bicarbonates such as for example sodium chloride, sodium sulfate, sodium nitrate, sodium bromide, sodium carbonate, sodium bicarbonate, potassium chloride, calcium chloride, magnesium chloride, magnesium sulfate, potassium sulfate. Preferably, the brine has a salinity of from 70 to 350 g / L, preferably from 120 to 270 g / L.

[0081] Preferably, the brine has a total dissolved solids (TDS) of from 70 to 400 g / L, preferably from 150 to 300 g / L, more preferably from 200 g / L to 270 g / L. According to an embodiment, the aqueous solution, preferably the brine, injected in step i) and / or in step ii) of the method according to the invention comprises the surfactant dissolved therein.

[0082] The aqueous solution, preferably the brine, may also comprise one or more additives. Such additives may include sacrificial agents, nanoparticles, temperature and / or pressure stabilizers, mobility control polymers, oxygen scavengers, pH adjustment agents, solvents and mixtures thereof.

[0083] The aqueous solution injected in step i) may be the same or different from the aqueous solution injected in step ii).

[0084] Preferably, the aqueous solution injected in both steps is the same.

[0085] Surfactant

[0086] The surfactant to be injected in step i) and / or in step ii) of the method according to this disclosure can be in particular any surfactant suitable for methods of enhanced oil recovery and / or of CO2 sequestration.

[0087] In particular, the surfactant can be selected from a nonionic surfactant including for example alcohol ethoxylates and alkylphenol ethoxylates, an anionic surfactant including for example sulfonates, sulfates and carboxylates, a cationic surfactant, including for example quaternary ammonium compounds and amines, a zwitterionic surfactant such as betaines, and combinations thereof.

[0088] Preferably, the surfactant is (or comprises) a cationic surfactant.

[0089] According to a preferred embodiment of the present disclosure, the surfactant is (or comprises) a compound of formula (I):

[0090] R2zR3

[0091] N — A— N

[0092] R1 R 4wherein R1, R2, R3, and R4 are independently a hydrogen atom or an alkyl group, A is an alkylene group, and the total number of carbon atoms in the surfactant compound of formula (I) is from 10 to 24.

[0093] Each R1, R2, R3, and R4 alkyl group in the compound can be linear or branched.

[0094] The alkylene group A can be linear or branched and is preferably linear.

[0095] The alkyl and alkylene groups are preferably non-substituted. Therefore, the alkyl groups are advantageously of formula -CnH2n+i, where n is an integer, and the alkylene groups A have the formula -CnH2n-, where n is an integer. According to some embodiments, the total number of carbon atoms in the compound of formula (I) is 11 , or 12, or 13, or 14, or 15, or 16, or 17, or 18, or 19, or 20, or 21 , or 22, or 23, or 24. Preferred ranges of carbon atoms are from 15 to 23, from15 to 22, from15 to 20, or from 16 to 20, preferably from 16 to 19, and more preferably from 17 to 19.

[0096] In some embodiments, the group A may comprise 1 carbon atom, 2 carbon atoms, 3 carbon atoms, 4 carbon atoms, 5 carbon atoms, or 6 carbon atoms. Number of carbon atoms of from 1 to 5 and from 2 to 4 are preferred. According to a preferred embodiment, A is -C3H6-.

[0097] In some embodiments, at least one of R1, R2, R3 and R4 is a hydrogen atom. Preferably, only one among R1, R2, R3 and R4 is a hydrogen atom, and the other three are alkyl groups. In such a case, the compound is a diamine compound comprising both a secondary amine function and a tertiary amine function.

[0098] The alkyl groups among R1, R2, R3 and R4 can be linear and / or branched. According to some preferred embodiments, one (and only one) of the alkyl groups among R1, R2, R3 and R4 is branched. According to other preferred embodiments, all the alkyl groups among R1, R2, R3 and R4 are linear.

[0099] Preferably, one and only one among R1, R2, R3 and R4 is a hydrogen atom. Therefore, in some preferred embodiments, one and only one of R1, R2, R3 and R4 is a hydrogen atom and one and only one of R1, R2, R3 and R4 is a branched alkyl group. In other preferred embodiments, one and only one of R1, R2, R3 and R4 is a hydrogen atom and the other three of R1, R2, R3 and R4 are linear alkyl groups.

[0100] Preferably, one (and only one) of R1, R2, R3 and R4 is an alkyl group having a relatively long carbon chain, i.e. comprises at least 6 carbon atoms. The long chain alkyl group preferably comprises at least 7, at least 8, at least 9, at least 10, at least 11 , or at least 12 carbon atoms. Preferred numbers of carbon atoms for this group may range from 8 to 16, or from 10 to 16, or from 11 to 15, or from 12 to 14.

[0101] Alternatively, two of R1, R2, R3 and R4 are alkyl groups having a relatively long carbon chain, for example containing at least 6 carbon atoms, possibly at least 7 carbon atoms or at least 8 carbon atoms. In this case, the long chain alkyl groups are preferably geminal, for example they can be R1 and R2, or R3 and R4.

[0102] Preferably, the other groups among R1, R2, R3 and R4 are hydrogen atoms or short chain alkyl groups, for example alkyl groups comprising 1 to 3 carbon atoms, preferably 1 to 2 carbon atoms, and most preferably a single carbon atom (i.e. methyl groups). In one preferred embodiment, one among Ri, R2, R3 and R4 is a hydrogen atom, one among R1, R2, R3 and R4 is a long chain alkyl group as defined above, and the other two among R1, R2, R3 and R4 are short chain alkyl groups as defined above, and more preferably methyl groups. In another preferred embodiment, two among R1, R2, R3 and R4 are long chain alkyl groups as defined above, and the other two among R1, R2, R3 and R4 are short chain alkyl groups as defined above, and more preferably methyl groups.

[0103] Examples of preferred compounds of formula (I) are those listed in the table below:

[0104] Advantageously, the compound of formula (I) is selected from the groups consisting in N1-dodecyl-N3,N3-dimethylpropane-1 ,3-diamine, N1-dodecyl- N1,N3,N3-trimethylpropane-1 ,3-diamine, N1-(2,2-diethyloctyl)-N3,N3- dimethylpropane-1 ,3-diamine, N1-octyl-N3,N3-dimethylpropane-1 ,3-diamine, N1- decyl-N3,N3-dimethylpropane-1 ,3-diamine, N1-tetradecyl-N3,N3-dimethylpropane- 1 ,3-diamine, N1-hexadecyl-N1,N3,N3-trimethylpropane-1 ,3-diamine, N1- heptadecyl-N1,N3,N3-trimethylpropane-1 ,3-diamine, N1-octadecyl-N1,N3,N3- trimethylpropane-1 ,3-diamine, and N-dodecyl-1 ,3-propanediamine.

[0105] According to a most preferred embodiment, the surfactant of formula (I) is N1-dodecyl-N3,N3-dimethylpropane-1 ,3-diamine of formula:

[0106] Compounds of formula (I) may be synthesized according to techniques well known in the art, for example by reducing compounds having the same formula, except that one of the alkyl groups is replaced by a corresponding acyl group which therefore forms an amide bond with the neighboring nitrogen atom.

[0107] By way of example, the preferred compound N1-dodecyl-N3,N3- dimethylpropane-1 ,3-diamine can be reduced from dodecylamidopropyl dimethylamine according to the following reaction scheme:

[0108] A similar reduction reaction can also be performed starting from a complex mixture, such as cocam idopropyl dimethylamine (which is a mixture of amide compounds, predominantly having a Cs-C alkyl chain).

[0109] The reduction reaction may be performed in the presence of sodium bis(2- methoxyethoxy)aluminumhydride in toluene. Other possible reducing agents include LiAIH4 and NaBH4.

[0110] The amide starting compounds may be obtained by reacting the corresponding carboxylic acid and amine. For instance, dodecylamidopropyl dimethylamine may be obtained by reacting the carboxylic acid of the following formula: with the diamine of the following formula:

[0111] The amidation reaction may be performed for example in the presence of a coupling agent such as 2-(1 H-benzotriazol-1 -yl)-1 ,1 ,3,3-tetramethyluronium hexafluorophosphate, of a base such as triethylamine, and in a solvent such as dimethylformamide and / or tetrahydrofurane.

[0112] In some variants, step (i) and / or step ii) may include the injection of a single surfactant compound of formula (I).

[0113] In some other variants, step (i) and / or step ii) may include the injection of at least two surfactant compounds of formula (I).

[0114] In particular, the surfactant can be a plurality of surfactant compounds of formula (I), preferably with a statistical distribution. In preferred variants, A, R2, R3 and R4 are the same for the plurality of surfactant compounds, and R1 is a different alkyl group. In more preferred variants, A is C3H6, R2 is H, R3 and R4 are methyl groups in the various surfactant compounds of formula (I), while R1 is a different alkyl group, such as in particular an alkyl group, preferably a linear alkyl group, comprising 8 to 16 carbon atoms or comprising 12 to 14 carbon atoms.

[0115] According to a preferred embodiment, step (i) and step ii) include both the injection of a single surfactant.

[0116] The surfactant used in the second step (ii) can either remain the same as that used in the first step (i) or vary. According to a preferred embodiment, the surfactant is the same in both steps (i) and (ii). Preferably, the surfactant in both steps is N1-dodecyl-N3,N3-dimethylpropane-1 ,3-diamine.

[0117] Advantageously, in step ii) and i), the surfactant can be included and / or dissolved in the aqueous solution, in the CO2, preferably in liquid or supercritical state, or in both.

[0118] According to a preferred embodiment, in step i) and / or in step ii) the surfactant is dissolved in the aqueous solution.

[0119] According to some embodiments, in step i) and / or in step ii) the concentration of the injected surfactant in the aqueous solution, in CO2 or in both is from 500 to 50,000 ppm, preferably from 1 ,000 to 20,000 ppm, more preferably from 1000 to 7,000 (w / v), relative to the total volume of the ingredients injected in step i) or in step ii).

[0120] According to an embodiment of the present invention, the concentration of the surfactant injected in step i) is higher than the concentration of the surfactant injected in step ii). According to a preferred embodiment, the concentration of the surfactant injected in step i) is from 3,000 to 7,500 ppm and the concentration of the injected surfactant in step ii) is from 1 ,000 to 2,800 ppm.

[0121] According to another embodiment of the present invention, the concentration of the surfactant injected in step i) is equal to the concentration of the surfactant injected in step ii).

[0122] The applicant has discovered that significant acceleration in foam formation occurs particularly when the formation is pre-flushed with a slug containing a low CO2 fraction and a high concentration of surfactant, followed by an increase in the CO2 fraction while reducing the surfactant concentration.

[0123] The method for enhancing carbon dioxide foam generation and / or propagation

[0124] The foam generated from the mixture of surfactant and CO2 according to the invention can be created through various methods.

[0125] One approach involves generating the foam on the surface by mixing the aqueous solution, the surfactant and CO2 in a suitable device and then injecting the foam into the subterranean formation through at least one injection well.

[0126] Alternatively, the foam can be formed in situ by injecting the ingredients separately (simultaneously or not) through at least one injection well, in particular with different streams for the aqueous solution and the CO2. Another method involves mixing two or more components at the surface before introducing them into the subterranean formation through at least one injection well.

[0127] According to a variant, in step i) and / or in step ii), the aqueous solution, the surfactant and the CO2 are injected simultaneously.

[0128] For example, step i) and / or step ii) can include the injection of the aqueous solution comprising the surfactant, and CO2 either as a mixture or separately but simultaneously. In particular, the aqueous solution, the surfactant and the CO2 can be mixed together at the surface prior to introduction into the subterranean formation. Alternatively, the aqueous solution and the surfactant are mixed together and the resulting solution is then injected simultaneously with CO2.

[0129] According to another variant, step i) and / or step ii) include the sequential injection of the aqueous solution and the CO2.

[0130] For example, step i) and / or step ii) can include the injection of the aqueous solution comprising the surfactant followed by the injection of CO2. Alternatively, step i) can include the injection of CO2 followed by the injection of the aqueous solution comprising the surfactant. Alternatively, step i) can include the injection of the aqueous solution followed by the injection of CO2 comprising the surfactant. Alternatively, step I) and / or step ii) can include the injection of CO2 comprising the surfactant first then injection of the aqueous solution.

[0131] Specifically, the method according to the invention may further comprise a step, prior to step i), of premixing the surfactant and carbon dioxide in the liquid state or in the supercritical state to make a CO2-surfactant composition. Step i) may thus include the injection of the CO2-surfactant composition into the subterranean formation via the same inlet followed by the aqueous solution.

[0132] The sequential injection of the aqueous solution, surfactant and carbon dioxide can be performed via one or several injection wells.

[0133] The method according to the invention is particularly effective if the subterranean formation exhibits unfavorable characteristics, such as a significant minimum pressure gradient and its dependance on the CO2 fraction. In this type of formation, even after adsorption of the surfactant onto the surface of the formation is complete, it remains difficult to generate foam in these conditions.

[0134] According to an embodiment, the method according to the invention may further comprise a step, prior to step i), of pre-flushing the subterranean formation with an aqueous solution and a surfactant as defined above without injecting CO2.

[0135] The conditions in the injection steps i) and ii), in particular the pressure and the temperature, are known to those skilled in the art. For example, the ingredients can be typically injected at the entrance of the well at pressures ranging from 50 to 300 bar, preferably from 100 to 200 bars, and temperatures between 0°C and 200°C, preferably between 15°C and 150 °C. Those skilled in the art know how to adjust the exact conditions depending on the specific subterranean formation characteristics.

[0136] Applications

[0137] According to one aspect, the method for generating and / or propagating carbon dioxide foam in a subterranean formation, as disclosed herein, is used to improve oil recovery from the subterranean formation.

[0138] Advantageously, according to this aspect, the subterranean formation is an oil-bearing reservoir, in particular that has already undergone primary and secondary recovery methods.

[0139] Advantageously, according to this aspect, the method further comprises a step iii) of recovering hydrocarbons from the subterranean formation.

[0140] According to another aspect, the method for generating and / or propagating carbon dioxide foam in a subterranean formation, as disclosed herein, is used for CO2 sequestration or CO2 storage. For the purpose of this disclosure, the terms " CO2 sequestration" and "CO2 storage" are used synonymously.

[0141] According to this aspect of the disclosure, the subterranean formation advantageously refers to a structure capable of long-term storing CO2, for example having sufficient porosity and permeability for CO2 injection and storage. The subterranean formation may be a hydrocarbon-bearing reservoir or a formation that contains little or no hydrocarbons, such as a depleted hydrocarbon- bearing reservoir. In some embodiments, the subterranean formation may be a water-bearing formation, notably of clastic or carbonate nature, for example, an aquifer, in particular a saline aquifer.

[0142] Preferably, according to this aspect, the subterranean formation is an aquifer.

[0143] Advantageously, according to this aspect, the method further comprises a step iii’) of collecting water present in the subterranean formation.

[0144] Preferably, steps i) and ii) of the method are typically conducted via at least one injection well, whereas steps iii) or step iii’) are conducted through at least one production well. Preferably, the injection well(s) comprise(s) one or more pipeline(s) connected to respective dosimetric pump(s).

[0145] Preferably, in both aspects, the production well(s) is / are located at a distance of from 1 to 100 km, preferably from 10 to 50 km, from the at least one injection well via which the injecting step(s) is / are carried out.

[0146] In one embodiment, step iii) or step iii’) is conducted after step ii).

[0147] In another embodiment, step iii) or iii’) is conducted concurrently with steps i) and / or ii).

[0148] The method according to the invention may also comprise one or more additional steps between step ii) and step iii) or step iii’), such as water injection, polymer flooding and / or steam injection.

[0149] EXAMPLES

[0150] The following examples illustrate the invention without limiting it.

[0151] I- Materials and methods:

[0152] 1.1 - Preparation of a brine-surfactant solution:

[0153] To prepare the brine solution, NaCI (Aldrich, 99.5%), CaCl2’2H2O (Merck, 99%), MgCl2-6H2O (Acres Organics, 99%), Na2SO4(VWR, 99.8%), NaHCO3(VWR, 100.0%), and deionized water were used. The detailed composition of the brine is described in Table 1 , with the final solution having a total dissolved salts (TDS) concentration of 257.55 g / L. The viscosity of the brine was 0.44 cP at 110°C and 1.34 cP at 28°C. Table 1 : Composition of the brine

[0154] The surfactant N1 -dodecyl-N3,N3-dimethylpropane-1 ,3-diamine, developed by TotalEnergies S.E (R-CADA, purity 90%) was then incorporated into the brine. Two surfactant solutions were prepared at a concentration of 2000 ppm and 5000 ppm respectively.

[0155] The pH was adjusted to 6 using a HCI 0.01 M solution to ensure surfactant solubility. The surfactant solutions were prepared in a glove box to carefully remove oxygen. 20 ppm of carbohydrazide as an oxygen scavenger was added to the surfactant solutions to prevent surfactant degradation at high temperatures.

[0156] 1.2- CO2:

[0157] The CO2 source was liquid CO2 stored in a 40 L tank provided by Linde Co., with a purity of 99.9%. The viscosity of CO2 is 0.027 cP at 110°C and 0.083 cP at 28°C according to the NIST webbook.

[0158] Coreflood experiments were performed at 150 barg and 110°C or 28°C on sandpacks, and at 150 barg and 110°C on limestones. Under these conditions, the CO2 is in the supercritical or liquid state, respectively.

[0159] 1.3- Core sample preparation:

[0160] A sandpack was created by tightly packing silica sand (MI31 N°0 from Sibelco Co.) into a HPLC stainless-steel column, achieving a permeability of approximately 14,000 mD. All the parameters of the sandpack are listed in Table 2. Table 2: Parameters of the sandpack

[0161] 1.4- Characterization of CO2 foam mobility and strength:

[0162] To describe the mobility and strength of the CO2 foam, the measured pressure gradient AP is converted into apparent viscosity AV with the following equation based on the single-phase Darcy law: where k is the absolute permeability, A is the core cross-section, q is the total volumetric injection rate and L is the core length.

[0163] The pore volume (PV) was measured by a gas method at first. Then, a sample was evacuated and flushed with CO2 several times before vacuum saturation by several pore volumes of 3% NaCI brine. Miscible tracer tests were then carried out to estimate the homogeneity and longitudinal dispersion coefficient (aD). Tracer studies were performed by measuring UV absorbance (UPC-900 from AKTA Co.) of effluent produced by the 3% NaCI brine containing 1 .6 g / L KI at a flow rate of 120-180 cm3 / h. Subsequently, the back pressure was increased to 150 barg, and for limestones, a confining pressure was set to 220 barg. The brine was then injected to pre-condition the core sample and the temperature of the oven was increased to 110°C. Absolute water permeability (k) was measured with the brine.

[0164] II- Experimental procedures:

[0165] At the beginning of the experiment, the brine-surfactant solution and CO2 were co-injected through a bypass line for purging the connecting lines and stabilizing a back pressure regulator (BPR, from Jasco Co., model BP-4340). Then, the brine-surfactant solution and CO2 were co-injected through two separate lines that converge at the entrance of the core at a target volume fraction of CC>2 and pressure drop across the entire sample was measured.

[0166] The experiments were conducted once at 28°C and once at 110°C and included an initial step of pre-flushing the sandpack with a CO2 fraction of 48% and 5000 ppm of surfactant dissolved in brine. Following this, the target CO2 fraction of 95% and 2000 ppm of surfactant (in brine) were injected. These experiments were compared to a method that omitted the pre-flushing step, where the CO2 was directly injected at a CO2 fraction of 95% together with 2000 ppm of surfactant (in brine).

[0167] All experiments were carried out at a constant injection flow rate. The flow rate of CO2 was controlled with ISCO dual pump maintained at 28°C and the flow rate under the conditions of the experiment was calculated using the CO2 densities from NIST webbook.

[0168] Between each experiment, the sandpack was restored to the initial conditions by flooding with distilled water for many pore volumes at ambient pressure since both CO2 and the surfactant are soluble in water. The absolute water permeability was checked to confirm sample restoration.

[0169] The indicated CO2 fractions are volumetric and calculated in situ; they are in particular corrected for CO2 solubility in brine, calculated based on the model described in Yan, W., Huang, S., & Stenby, E. H. (2011 ), Measurement and modeling of CO2 solubility in NaCI brine and CO2-saturated NaCI brine density, International Journal of Greenhouse Gas Control, 5(6), 1460-1477, i.e., the injections were performed at a higher nominal CO2 fraction, but part of CO2was dissolved in the brine and part of the water was vaporized in the CO2, leading to a lower in-situ CO2 fraction.

[0170] Results: The results of the experiments are shown on Figure 2.

[0171] Pre-flushing the sandpack with a foam containing 5000 ppm of surfactant R-CADA solution at a lower CO2 fraction significantly accelerated foam generation in the experiments conducted at both 28°C (Figure 2a) and 110°C (Figure 2b). This pre-flushing step reduced the MPV from approximately 9 PV to about 0.2 PV and the PVP from around 20 to 3.8 PV.. These results demonstrate that employing a surfactant-enriched pre-flush at a lower CO2 fraction effectively enhances foam generation and propagation when injecting at a higher CO2 fraction.

Claims

CLAIMS1. A method for generating and / or propagating carbon dioxide foam in a subterranean formation, successively comprising at least the steps of: i) injecting into the subterranean formation at least an aqueous solution, a surfactant, and carbon dioxide at a fraction F1 co2, ii) injecting into the subterranean formation, at least an aqueous solution, a surfactant and carbon dioxide at a fraction F2co2, wherein the carbon dioxide fraction F2co2 is higher than the carbon dioxide fraction F1 co2.

2. The method of claim 1 , wherein the surfactant in step i) and / or in step ii) is a compound of formula (I):R2 R3N — A—(|)R1R4 wherein Ri, R2, R3, and R4 are independently a hydrogen atom or an alkyl group, A is an alkylene group, and the total number of carbon atoms in the surfactant compound of formula (I) is from 10 to 24.

3. The method of claim 2, wherein in formula (I), A comprises from 1 to 5 carbon atoms, preferably from 2 to 4 carbon atoms, and more preferably comprises 3 carbon atoms.

4. The method of claim 2 or claim 3, wherein at least one of R1, R2, R3 and R4 is an alkyl group comprising from 8 to 16 carbon atoms, preferably from 10 to 15 carbon atoms, and more preferably from 12 to 14 carbon atoms.

5. The method of any one of claims 1 to 4, wherein A comprises 3 carbon atoms, R1 is an alkyl group comprising from 6 to 16 carbon atoms, R2 is a hydrogen atom, R3 is a methyl group and R4 is a methyl group.

6. The method of any one of claims 1 to 5, wherein the compound of formula (I) is selected from N1-dodecyl-N3,N3-dimethylpropane-1 ,3- diamine, N1-dodecyl-N1,N3,N3-trimethylpropane-1 ,3-diamine, N1- (2,2-diethyloctyl)-N3,N3-dimethylpropane-1 ,3-diamine, N1-octyl- N3,N3-dimethylpropane-1 ,3-diamine, N1-decyl-N3,N3- dimethylpropane-1 ,3-diamine, N1-tetradecyl-N3,N3- dimethylpropane-1 ,3-diamine, N1-hexadecyl-N1,N3,N3- trimethylpropane-1 ,3-diamine, N1-heptadecyl-N1,N3,N3- trimethylpropane-1 ,3-diamine, N1-octadecyl-N1,N3,N3- trimethylpropane-1 ,3-diamine, and N-dodecyl-1 ,3-propanediamine.

7. The method of claim 6 wherein the compound of formula (I) is N1- dodecyl-N3,N3-dimethylpropane-1 ,3-diamine.

8. The method of any one of claims 1 to 7, wherein the carbon dioxide is liquid or supercritical carbon dioxide.

9. The method of any one of claims 1 to 8, wherein the surfactant is included and / or dissolved in the aqueous solution, in the CO2 or in both.

10. The method of any one of claims 1 to 9, wherein the aqueous solution is brine.

11. The method of claim 10, wherein the brine comprises one or more salts selected from alkali metal and alkaline earth metal chlorides, sulfates, nitrates, carbonates and bicarbonates.

12. The method of claim 10 or claim 11 , wherein the brine has a salinity of from 70 to 350 g / L, preferably from 120 to 270 g / L.

13. The method of any one of claims 1 to 12, wherein in step i) or in step ii), the concentration of the surfactant is from 500 to 50,000 ppm, preferably from 1 ,000 to 20,000 ppm, more preferably from 1000 to 7,000 (w / v).

14. The method of any one of claims 1 to 13, wherein the concentration of the surfactant injected in step i) is higher or equal than the concentration of the surfactant injected in step ii).

15. The method of any one of claims 1 to 14, the fraction of CO2 F1 co2 injected in step i) is at most 50%, preferably ranges from 5 % to 65%, preferably from 10% to 60%, more preferably, from 20% to 50%.

16. The method of any one of claims 1 to 15, the fraction of CO2 F2co2 injected in step ii) is 55% or higher, preferably between 70% and 99%, more preferably between 80 and 95%.

17. The method of claim 13, wherein in step i) and / or in step ii), the aqueous solution, the surfactant and the CO2 are injected simultaneously.

18. The method of claim 13, wherein step i) and / or step ii) include the sequential injection of the aqueous solution, the surfactant and the CO2.

19. The method of any one claim 1 to 18, wherein the CO2 foam is used for enhancing oil recovery from the subterranean formation.

20. The method of claim 19, wherein the method further comprises a step iii) of recovering hydrocarbons from the subterranean formation.

21. The method of any one claim 1 to 20, wherein the CO2 foam is used for CO2 sequestration into the subterranean formation.

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