Method for determining retention value

Abstract

The present invention relates to a method for determining a value of retention of a surfactant in a subterranean formation, comprising steps of: injecting a flow of a solution comprising water, the surfactant and CO2 into a subterranean formation or a sample thereof, wherein the subterranean formation comprises a carbonate mineral, and wherein the CO2 is substantially entirely dissolved in the solution, the content of the dissolved CO2 in the solution being at least 50% of the solubility limit of CO2 in the solution; collecting a flow of solution exiting the subterranean formation or the sample thereof; and measuring the concentration of the surfactant in the flow of solution exiting the subterranean formation or the sample thereof.

Description

[0001] METHOD FOR DETERMINING RETENTION VALUE

[0002] Technical field

[0003] The present invention relates to a method for determining a value of retention of a surfactant in a subterranean formation.

[0004] Technical background

[0005] During the injection of a surfactant into a subterranean formation (or a reservoir) for the purpose of oil recovery and / or improved of CO2 storage, a portion of this surfactant is retained in the subterranean formation. The loss by this retention needs to be quantified to ensure the process efficiency.

[0006] The values of retention are mainly determined using two methods: static and dynamic. Static tests do not necessitate sophisticated and costly equipment but have questionable reliability due to potential alterations in surface’s nature and charge caused by prior rock crushing and to the need for normalization by surface area to convert data into standard units (mg / g of rock).

[0007] As for the dynamic mode, the most representative method is performed by injecting a surfactant solution into a rock core, recovering it and dosing it at the outlet of the core. An in situ injection and dosing in subterranean reservoir is also possible.

[0008] For example, document US 11 ,286,771 describes a method for determining surfactant retention values in subterranean reservoirs. In particular, the method comprises conducting at least one single well chemical tracer test and performing a straight line analysis on a hydrocarbon saturation profile of the subterranean reservoir.

[0009] However, this method requires heavy investments and several steps of analysis using a tracer, which makes the method complex.

[0010] Besides, a specific problem is posed by the potential requirement of an acidic pH in a subterranean formation, for example due to the nature of the chemicals to be injected (CO2 typically), and / or to the nature of the surfactant to be used. In that case, it is mandatory that retention measurements be executed in such acidic conditions, because the chemical state of the rock surface (whatever the rock nature), which is key in the surfactant retention (adsorption) process, heavily depends on pH.

[0011] Especially, when the subterranean formation (or the rock core) comprises carbonate minerals, using a common acid to acidify the solution to achieve the relevant low pH can dissolve the rock, thereby disturbing the measurement.

[0012] For surfactant injections that require acidic conditions, such as the injection of a surfactant which is soluble in water only at acidic pH, the solubility can be guaranteed by the presence of CO2. However, simultaneous injection of the surfactant and CO2 into the subterranean formation (or the rock core) will lead to a two-phase flow (foam) and disturb the measurement.

[0013] Thus, there exists a continuous need for an efficient method which makes it possible to determine a value of retention of a surfactant in such conditions in a subterranean formation.

[0014] Summary of the invention

[0015] It is a first object of the invention to provide a method for determining a value of retention of a surfactant in a subterranean formation, comprising steps of:

[0016] - injecting a flow of a solution comprising water, the surfactant and CO2 into a subterranean formation or a sample thereof, wherein the subterranean formation comprises a carbonate mineral, and wherein the CO2 is substantially entirely dissolved in the solution, the content of the dissolved CO2 in the solution being at least 50% of the solubility limit of CO2 in the solution;

[0017] - collecting a flow of solution exiting the subterranean formation or the sample thereof; and

[0018] - measuring the concentration of the surfactant in the flow of solution exiting the subterranean formation or the sample thereof.

[0019] In some embodiments, the sample of the subterranean formation is a core from the subterranean formation, and the method further comprises a preliminary step of heating the core to a temperature T and pressurizing the core to a pressure P, wherein the temperature T and the pressure P are representative of natural conditions within the subterranean formation.

[0020] In some embodiments, the temperature T ranges from 30 to 200°C and the pressure P ranges from 2 to 250 barg.

[0021] In some embodiments, the pressure is controlled via a back pressure regulator. In some embodiments, the step of injecting the flow of the solution is performed via at least one injection well in the subterranean formation, and the step of collecting the flow of solution is performed via the injection well or via at least one production well in the subterranean formation.

[0022] In some embodiments, the solution is a brine solution.

[0023] In some embodiments, the subterranean formation comprises at least 5% by weight of the carbonate mineral.

[0024] In some embodiments, the injecting step comprises co-injecting a flow of liquid, supercritical or gaseous CO2 and a flow of a solution comprising water and the surfactant into the subterranean formation or sample thereof at temperature T and pressure P, wherein the liquid, supercritical or gaseous CO2 substantially or fully dissolves in the solution at temperature T and pressure P, thereby not generating a foam.

[0025] In some embodiments, the surfactant is soluble in water at acidic pH.

[0026] In some embodiments, the surfactant is a cationic surfactant.

[0027] In some embodiments, the flow of the solution comprises or is a singlephase flow.

[0028] In some embodiments, the retention is adsorption of the surfactant in the subterranean formation or sample.

[0029] In some embodiments, the content of the dissolved CO2 in the solution is at least 80%, preferably at least 90%, more preferably at least 95% of the solubility limit of CO2 in the solution.

[0030] In some embodiments, the content of the dissolved CO2 in the solution is at least 0.01 mol / kg of the solution, preferably at least 0.03 mol / kg, more preferably at least 0.05 mol / kg, ideally at least 0.08 mol / kg.

[0031] In some embodiments, the flow exiting the subterranean formation or sample thereof has a pH of from 3 to 8.

[0032] In some embodiments, the subterranean formation or sample thereof comprises less than 20% of oil, preferably is substantially devoid of oil.

[0033] In some embodiments, the method further comprises a step of injecting a flow of a test solution comprising a non-reactive agent into the subterranean formation or sample thereof, and measuring the concentration of the non-reactive agent in the flow of the test solution exiting the subterranean formation or sample thereof.

[0034] In some embodiments, the method further comprises a step of comparing a concentration profile of the surfactant in the solution exiting the subterranean formation or sample thereof and a concentration profile of the non-reactive agent in the test solution exiting the subterranean formation or sample thereof, wherein the concentration profile is a function of cumulative injection of the solution.

[0035] In some embodiments, the method further comprises a step of comparing the concentration of the surfactant in the solution to be injected into the subterranean formation or sample thereof and the concentration of the surfactant in the flow of solution exiting the subterranean formation or sample thereof.

[0036] The present invention enables to address the need mentioned above. In particular, the invention provides a method which makes it possible to determine a value of retention of a surfactant in a subterranean formation.

[0037] This is achieved by injecting a flow of a solution comprising water, the surfactant and CO2 into a subterranean formation or a sample thereof, wherein the subterranean formation comprises a carbonate mineral, and wherein the CO2 is substantially entirely dissolved in the solution.

[0038] By “sample of the subterranean formation” is herein meant that the sample is representative of the subterranean formation, to which the surfactant is eventually applied in an application such as EOR or carbon storage. Thus, as the subterranean formation comprises a carbonate mineral, the same applies to the sample; the value of retention measured on a sample according to the method corresponds to the value of retention in the subterranean formation or at least makes it possible to accurately evaluate said value.

[0039] According to the method of the invention, the presence of CO2 substantially entirely dissolved in the solution acidifies the solution by generating H+ions without dissolving the subterranean formation (or sample thereof) comprising a carbonate mineral.

[0040] The subterranean formation (or sample thereof) comprising a carbonate mineral generates carbonate ions (such as HCOs' and COs2') when dissolved. However, the CO2 dissolved in the solution also generates carbonate ions in addition to H+. The presence of these carbonate ions generated by the dissolved CO2 establishes an equilibrium that effectively prevents the dissolution of the subterranean formation (or sample).

[0041] Therefore, CO2 plays a unique role as an acidifying agent, in that it substantially prevents the dissolution of carbonate minerals, unlike most other acids.

[0042] Thus, one advantage of the invention is that the pH of the solution can be controlled while the integrity of the subterranean formation (or sample thereof) is well maintained, thereby allowing for a more reliable and accurate measurement of the value of retention of the surfactant in a subterranean formation. Brief description of the drawings

[0043] Figure 1 schematically illustrates one example of a setup for implementing the method of the invention.

[0044] Figure 2 shows concentration profiles of a surfactant and tracers on the left Y-axis along with variations in pH on the right Y-axis, as a function of cumulative injection (X-axis). The profile A corresponds to the concentration of the tracers. The circles represent the measured concentration values of the surfactant, forming the profile B. The crosses represent the pH values.

[0045] Detailed description

[0046] The invention will now be described in more detail without limitation in the following description.

[0047] The term “retention (of a surfactant)” as used herein refers to the phenomenon in which a surfactant, when introduced into a subterranean formation (or sample thereof), remains or is trapped within the subterranean formation (or sample). The retention mainly involves adsorption and / or precipitation.

[0048] The term “adsorption” as used herein refers to the phenomenon in which the surfactant adheres to the surface of solid materials (such as rocks).

[0049] The term “precipitation” as used herein refers to the phenomenon in which the surfactant accumulates on the surface of solid materials (such as rocks), due to the surfactant’s insolubility in the solution or its interaction with residual oil present in the rocks.

[0050] The term “core” as used herein refers to a cylindrical rock sample taken from a subterranean formation using, for example, drilling techniques.

[0051] The present invention relates to a method for determining a value of retention of a surfactant in a subterranean formation, comprising steps of: injecting a flow of a solution comprising water, the surfactant and CO2 into a subterranean formation or sample thereof; collecting a flow of solution exiting the subterranean formation or sample thereof; and measuring the concentration of the surfactant in the flow of solution exiting the subterranean formation of sample thereof.

[0052] The subterranean formation (or the sample) comprises a carbonate mineral.

[0053] The CO2 is substantially entirely dissolved in the solution, and the content of the dissolved CO2 in the solution is at least 50% of the solubility limit of CO2 in the solution. By "substantially entirely dissolved" is meant that only a very small amount of CO2 remains undissolved, or preferably no CO2 is left undissolved. In other words, no gas bubble of CO2 is formed (and thus there is no formation of a foam).

[0054] The solubility limit of CO2 may be measured by a conventional method known in the art, typically using a standard PVT (pressure-volume-temperature) pressure cell under the conditions of the study. The solubility limit of CO2 may be also estimated by using a mathematical or computational model such as Peng- Robinson-Soreide-Whitson-Yan EOS model. For example, at 110°C, the solubility of CO2 in water with a salinity of 230 g / L (such as a brine from Tablel in Examples as below) is 6.2% by volume under a pressure of 150 barg and 5 % by volume under a pressure of 220 barg in the same brine.

[0055] The flow of a solution comprising water, the surfactant and CO2 may be injected into the subterranean formation (or sample), using a pump.

[0056] The pump may be a syringe pump, a pneumatic pump, and / or a reciprocating pump, or any type of pump depending on the scale of the operation.

[0057] The initial concentration value of the surfactant in the solution to be injected may be from 1000 ppm to 3000 ppm, for example from 1000 ppm to 2000 ppm, or from 2000 ppm to 3000 ppm, by weight.

[0058] The concentration of the surfactant in the flow of solution exiting the subterranean formation (or sample) may be measured by HPLC-CAD, NMR, or Mass Spectroscopy.

[0059] In some embodiments, the sample of subterranean formation may be a core from the subterranean formation.

[0060] In this case, the method may further comprise a preliminary step of heating the core to a temperature T and pressurizing the core to a pressure P, wherein the temperature T and the pressure P are representative of natural conditions within the subterranean formation.

[0061] For example, the temperature T may range from 30 to 200°C, and the pressure P may range from 2 to 250 barg.

[0062] The pressure may be controlled via a back pressure regulator.

[0063] A back pressure regulator can be any device or a valve that maintains a defined pressure upstream of its own inlet.

[0064] The solution may be a brine solution.

[0065] The brine solution may comprise inorganic salts.

[0066] The inorganic salts may comprise, for example, NaCI, KCI, CaCl2*2H2O, MgCI2*6H2O, Na2SO4, NaHCO3, and NaBr. The brine solution may have a total salt concentration (or salinity) of from 5 to 300 g / L, for example, from 5 to 100 g / L, from 100 to 200 g / L, or from 200 to 300 g / L.

[0067] As another example, the brine solution may have a salinity equivalent to NaCI of from 5 to 300 g / L, for example, from 5 to 100 g / L, from 100 to 200 g / L, or from 200 to 300 g / L.

[0068] The brine solution may have a total dissolved solid (TDS) concentration of from 5 to 300 g / L, for example, from 5 to 100 g / L, from 100 to 200 g / L, or from 200 to 300 g / L.

[0069] The brine solution may have an ionic force of from 0.1 to 6 mol / L, for example, from 0.1 to 1 mol / L, from 1 to 2 mol / L, from 2 to 3 mol / L, from 3 to 4 mol / L, from 4 to 5 mol / L, or from 5 to 6 mol / L.

[0070] The pressure range, the temperature range and / or the salinity as described above allow for better reproduction of the natural conditions of the subterranean formation, resulting in a more accurate and predictive determination of the value of retention.

[0071] The core may comprise a consolidated rock and / or non-consolidated rock (such as sand).

[0072] The core may be confined in a core holder by pressurizing fluid at a pressure (called confinement pressure) via a back pressure regulator.

[0073] The holder may be, for example, a sleeve made from rubber, polymer and / or metal.

[0074] The core length may be for example from 30 to 40 cm, preferably 30 to 35 cm. Such a length can largely decrease the capillary end effect (at typical flow rates of the subterranean formation), minimize the foam entrance effect, and provide reliable mass balance.

[0075] When the sample of subterranean formation is a core from the subterranean formation, the step of injecting the flow of the solution may be performed via at least one injection system (such as an injection line, an injection pipe or an injection channel), and the step of collecting a flow of solution exiting the subterranean formation sample may be performed via at least one collection system (such as a collection line, a collection pipe or a collection channel).

[0076] In other embodiments, the method is implemented in situ in the subterranean formation, for example via a single well tracer test (SWTT test), or via a 2-spots test.

[0077] In this case, the step of injecting the flow of the solution may be performed via at least one injection well, and the step of collecting a flow of solution exiting the subterranean formation may be performed via the same injection well (SWTT test) or via at least one production well (2-spots test).

[0078] The solution may be a brine solution which comprises inorganic salts, as described above in relation to the case of the subterranean formation core. The salinity and TDS concentration may be as described above. This is advantageous especially when the solubility of the surfactant varies depending on the salt concentration.

[0079] In the method of the invention, the subterranean formation (or the sample thereof) may comprise at least 5% by weight of carbonate minerals. For example, the subterranean formation (or sample thereof) may comprise at least 5% by weight, at least 10% by weight, at least 20% by weight, at least 30% by weight, at least 40% by weight, at least 50% by weight, at least 60% by weight, at least 70% by weight, at least 80% by weight, or at least 90% by weight, or substantially 100% by weight of carbonate minerals.

[0080] A carbonate mineral may be any mineral that contains a carbonate ion. For example, carbonate minerals may comprise calcium carbonate (such as limestone), magnesium carbonate, iron carbonate, and / or ankerite (Ca(Fe,Mg,Mn)(CO3)2).

[0081] In some embodiments, the injecting step may comprise co-injecting a flow of liquid, supercritical or gaseous CO2 and a flow of a solution comprising water and the surfactant into the subterranean formation (or sample thereof) at temperature T and pressure P.

[0082] In this case, the liquid, supercritical or gaseous CO2 substantially or fully dissolves in the solution at temperature T and pressure P, in view of the respective amounts or flow rates of CO2 and solution, thereby not generating a foam.

[0083] For example, when the method is implemented on a core from the subterranean formation, the liquid, supercritical or gaseous CO2 and the solution may be injected simultaneously, for example via different injection lines (or pipes or channels).

[0084] The flow rate of co-injection into the core may be appropriately selected. For example, the flow rate of co-injection may be from 3 to 6 ft / day, for example, from 3 to 4 ft / day, from 4 to 5 ft / day, or from 5 to 6 ft / day.

[0085] The flow rate herein is defined as the superficial velocity in the core (volumetric flow rate of the fluid divided by the cross-sectional area of the injection system).

[0086] When the method is directly implemented in situ in the subterranean formation, the liquid, supercritical or gaseous CO2 and the surfactant may be injected simultaneously via the same injection well(s). In this case, they can be injected via distinct inlets within a same injection well or via the same inlet.

[0087] The flow rate of co-injection into the part of the subterranean formation may be appropriately selected. For example, the flow rate of co-injection may be from 1 to 10000 ft / day, based on the superficial velocity .

[0088] In other embodiments, the injecting step may comprise pre-mixing CO2, water and the surfactant so as to form a mixture comprising water, the surfactant and CO2, in which CO2 is entirely dissolved in the mixture, thereby forming the solution comprising water, the surfactant and CO2.

[0089] The flow rate of injection may be as described above in relation to the case of co-injection.

[0090] The surfactant may be soluble in water at acidic pH. The surfactant may be insoluble in water at alkaline pH. The surfactant may be more soluble in water at acidic pH than at alkaline pH. Also, the surfactant may be soluble in water at any pH.

[0091] Since the method makes it possible to lower the pH of the solution by the dissolved CO2 (thereby solubilizing such a low pH-soluble surfactant), the surfactant does not substantially precipitate within the subterranean formation or the sample. This allows for the determination of a value of retention which is especially caused by adsorption. This is also beneficial for the eventual application of the surfactant in the subterranean formation for oil recovery and / or improved CO2 storage, as it helps to reduce the retention loss of the surfactant.

[0092] The surfactant may be an ionic surfactant, anionic or cationic, or a nonionic surfactant, or an amine switchable surfactant, preferably a cationic surfactant.

[0093] The adsorption of a cationic surfactant on carbonate minerals is presumably small at low pH since both are charged positively. Thus, since the method of the invention makes it possible to lower the pH of the solution, the use of a cationic surfactant is advantageous for its potential application to the subterranean formation for, for example, oil recovery and / or improved CO2 storage.

[0094] The surfactant may be an amine surfactant, such as monoamine surfactant or a diamine surfactant. For example, the surfactant may be a monoamine ethoxylate surfactant, a diamine ethoxylate surfactant, or an alkyl di-tertiary amine surfactant.

[0095] In some embodiments, the surfactant may be a diamine surfactant having a formula (RI)(R2)N-A-N(RS)(R4), wherein R1, R2, R3, and R4 are independently a hydrogen atom or an alkyl group, A is an alkylene group, having the total number of carbon atoms of from 10 to 24, such as C8-i6NH(CH2)3N(CHs)2, more specifically Ni-dodecyl-N3,N3-dimethylpropane-1 ,3-diamine.

[0096] The solution may further comprise an additive for preventing the degradation of the surfactant in the solution. For example, in the case of a surfactant which is degraded in the presence of oxygen, the additive may be a reducing agent or an oxygen scavenger.

[0097] In the method of the invention, the flow of the solution may comprise or may be a single-phase flow.

[0098] By “single-phase flow” is meant a flow of a single and continuous phase, unlike a multiphase such as a foam (gas bubbles (gas phase) dispersed in a liquid phase).

[0099] In some embodiments, the subterranean formation (or sample) may comprise less than 20 % by weight of oil, preferably is substantially devoid of oil.

[0100] Such a subterranean formation (or sample) may be representative of the subterranean formation in situ which has been subjected to EOR or a subterranean formation for an application of carbon storage.

[0101] In some embodiments, the retention is adsorption of the surfactant in the subterranean formation or sample.

[0102] In the presence of oil in the subterranean formation (or sample), some surfactant retention may occur due to some partitioning into the oil. Thus, especially when the subterranean formation (or sample) may comprise less than 20% of oil, preferably is substantially devoid of oil, the method makes it possible to specifically determine a value of retention caused by the adsorption, that is a value of adsorption. Additionally or alternatively, as explained above, when the surfactant is soluble in water at acidic pH, the method makes it possible to determine a value of adsorption, because the surfactant does not substantially precipitate within the subterranean formation or the sample due to the lowered pH.

[0103] In the method, the content of the dissolved CO2 in the solution is at least 80%, preferably at least 90%, more preferably at least 95%, and most preferably up to approximately 100% of the solubility limit of CO2 in the solution, for example, from 80 to 100%, 85 to 100%, 90 to 100%, or 95 to 100%.

[0104] For example, at 150 barg and 110°C, the content of the dissolved CO2 in the solution may be at least 0.01 mol / kg of the solution, preferably at least 0.03 mol / kg, more preferably at least 0.05 mol / kg, ideally at least 0.08 mol / kg, for example, from 0.01 mol / kg to 0.03 mol / kg, from 0.03 mol / kg to 0.08 mol / kg.

[0105] The solution may have a CO2 fraction of from 1 to 10% by volume, for example, from 1 to 3% by volume, from 3 to 6% by volume, or from 6 to 10% by volume, depending on temperature and pressure conditions. For example, at 150 barg and 110°C, the CO2 fraction may be from 1 to 10% by volume.

[0106] The pH of the surfactant solution to be injected into the subterranean formation (or sample) may be higher than the pH of the solution exiting the sample, for example in the case of co-injection.

[0107] For example, in that case, the pH of the solution to be injected into the subterranean formation (or sample) may be different from the pH of the collected solution by at least 1 , for example, at least 2, at least 3, or at least 4 units.

[0108] The pH of the solution to be injected into the subterranean formation (or sample) may be from 6 to 9, for example, from 6 to 7, from 7 to 8, or from 8 to 9, preferably from 6 to 7.

[0109] The flow exiting the subterranean formation (or sample) has a pH of from 3 to 8 for example, from 3 to 4, from 4 to 5, from 5 to 6, from 6 to 8, preferably from 3 to 4.

[0110] The pH may be measured according to the conventional method, for example, using a pH-meter.

[0111] The method may further comprise a step of injecting a flow of a test solution comprising a tracer non-reactive agent into the subterranean formation (or sample), and measuring the concentration of the non-reactive agent in the flow of the test solution exiting the subterranean formation or the sample.

[0112] The step of injecting the test solution comprising a tracer non-reactive agent may be performed before, at the same time as, or after the step of injecting the solution comprising water, surfactant and CO2.

[0113] The non-reactive agent herein refers to any agent that does not substantially interact with the subterranean formation or the sample, get adsorbed thereon, or precipitate within the subterranean formation or the sample.

[0114] The non-reactive agent may be any conventional reagent which can be used as a tracer, a label or a tag. For example, the non-reactive agent may be or comprise potassium iodide. When the step of injecting the test solution is performed at the same time as the surfactant solution, the tracer non-reactive agent is soluble in the surfactant solution, which may have a lowered pH, as described above.

[0115] The superficial velocity (flow rate) of the test solution may be from 0.1 to300 ft / day, for example, from 50 to 60 ft / day, from 60 to 70 ft / day, from 70 to 80 ft / day, from 80 to 90 ft / day, or from 90 to 100 ft / day, preferably from 70 to 80 ft / day when the subterranean formation sample is a core from the subterranean formation. The superficial velocity of the test solution may be from 1 to 300 ft / day when the method is directly implemented in situ in the subterranean formation, depending on permeability.

[0116] The initial concentration of the non-reactive agent in the test solution to be injected may be, for example, from 0.1 to 5% by weight, for example from 0.1 to 0.2% by weight, from 0.2 to 0.3% by weight, from 0.3 to 0.4% by weight, from 0.4 to 0.5% by weight, from 0.5 to 0.6% by weight, from 0.6 to 0.7% by weight, from 0.7 to 0.8% by weight, from 0.8 to 0.9% by weight, from 0.9 to 1 % by weight, from 1 to 2% by weight, from 2 to 3% by weight, from 3 to 4% by weight, from 4 to 5% by weight.

[0117] The concentration of the non-reactive agent may be measured by any suitable detector, such as an ultraviolet (UV) detector.

[0118] The test solution may further comprise inorganic salts.

[0119] The inorganic salts and their concentrations in the test solution may be as described above.

[0120] For example, the initial concentration of the inorganic salts in the test solution to be injected may be from 0.1 to 30% by weight, for example 0.1 to 1 %, from 1 to 2% by weight, from 2 to 3% by weight, from 3 to 4% by weight, from 4 to 5% by weight, from 5 to 6% by weight, from 6 to 7% by weight, from 7 to 8% by weight, from 8 to 9% by weight, from 9 to 10% by weight, from 10 to 20% by weight, or from 20 to 30% by weight.

[0121] The method of the invention may further comprise a step of comparing a concentration profile of the surfactant in the solution exiting the subterranean formation (or sample) and a concentration profile of the non-reactive agent in the test solution exiting the subterranean formation (or sample).

[0122] The concentration profile may be a set of concentration values acquired over a period of time, as the solution is collected. Instead of plotting the concentration over time, it is also possible to plot it against the cumulative volume of injected solution.

[0123] The cumulative volume of injected solution may be measured in a unit of pore volume (PV), which refers to the total volume of the injected solution relative to the pore volume of the subterranean formation (or sample).

[0124] The PV of the sample of subterranean formation may be measured by a gas method or using a solution comprising a non-reactive agent (which will be explained in Examples). In the case of in situ implementation, the PV 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 the porosity of the subterranean formation. In a concentration profile, in general, the concentration slowly increases with cumulative injection at the beginning of the injection. As more solution is injected into the subterranean formation (or sample), the concentration rises more rapidly, leading to an inflection point. Eventually, the concentration reaches a maximum value (normalized to 1 ), indicating equilibrium.

[0125] In this case, the value of retention may be determined by comparing the volume of the test solution injected for achieving 50% of the maximum (equilibrium) concentration of the non-reactive agent with the volume of the solution injected for achieving 50% of the maximum (equilibrium) concentration of the surfactant.

[0126] The value of retention of the surfactant may then be calculated in the unit of mg / g of sample of subterranean formation, using the following formula 1 :

[0127] ((PVs—PVT)pCs) / msample wherein PVs and PVT are injected volumes of the surfactant solution and the test solution, respectively (which is determined by multiplying the PV by the pore volume), p is water density at 25°C, Cs is the initial concentration of the surfactant in the solution to be injected, and mSamPie is a mass of the sample of subterranean formation (or of the area of the subterranean formation affected by the injected solution, in case of an in situ implementation).

[0128] Alternatively, the method may comprise a step of comparing the concentration of the surfactant in the solution to be injected into the subterranean formation (or sample) and the concentration of the surfactant in the collected flow of solution.

[0129] Before the surfactant solution (solution comprising water, the surfactant and CO2) and optionally the test solution is injected, the subterranean formation or the sample may be conditioned and / or pre-flushed beforehand. For example, the subterranean formation or the sample may be conditioned with a base solution (such as the same solution as the solution to be injected except that the surfactant (and optionally the non-reactive agent) is not contained.

[0130] Fig. 1 shows an example of the setup for implementing the method of the invention.

[0131] In this example, the method comprises co-injecting, into a sample of subterranean formation 1 , a flow of supercritical or gaseous CO2 2 and a flow of a solution comprising water and the surfactant 3.

[0132] The subterranean formation sample 1 is a core from the subterranean formation.

[0133] The pressure may be controlled via a back pressure regulator 4. The core may be confined in a core holder by a flow of pressurizing fluid 5 via back pressure regulator 4’.

[0134] The flow of CO2, the flow of the solution comprising water and the surfactant, and the pressurizing fluid are flowed using respective pumps 6, 6’, and 6”.

[0135] The pump for the flow of CO2 and for the flow of the pressurizing fluid may be syringe pumps.

[0136] The pump for the solution comprising water and the surfactant may be a high-performance liquid chromatography (HPLC) pump.

[0137] The flow of the solution exiting the subterranean formation sample may be collected, for example in a collection tube 8, and measured for the concentration of the surfactant.

[0138] The method may further comprise a step of injecting a flow of a test solution comprising a non-reactive agent 7 into the core 1 , and measuring the concentration of the non-reactive agent tracer in the flow of the test solution exiting the subterranean formation sample (downstream of the back pressure 4, for example, in a collection tube 8).

[0139] The following examples illustrate the method of the invention without limiting it.

[0140] Materials

[0141] - Surfactant: R-CADA (Ni-dodecyl-N3,N3-dimethylpropane-1 ,3-diamine)

[0142] - CO2: supercritical CO2

[0143] - Subterranean formation sample: core

[0144] - Core material: Estaillades limestone

[0145] - Core size: length of 30.1 cm and diameter of 3.80 cm

[0146] Preparation of a surfactant solution and a test solution

[0147] An R-CADA solution of a desired concentration in brine was prepared in a glovebox to cautiously remove the oxygen. The composition of the brine used for preparing the R-CADA solution is listed in Table 1 .

[0148] The pH of the solution was adjusted to about 6 by adding a low pH (pH=0.33) brine. The initial concentration value of the R-CADA solution was 2000 ppm. To avoid the degradation of R-CADA by residual oxygen under high temperature, 20 ppm of carbohydrazide (oxygen scavenger) was added into surfactant solution prepared in the glovebox.

[0149] The solution was then loaded into a stainless-steel transfer vessel in the glovebox.

[0150] A test solution comprising 0.166 wt.% potassium iodide (KI, non-reactive agent, referred to as a tracer) and 3 wt.% NaCI was prepared for tracer tests.

[0151] Table 1 . Composition of brine

[0152] Experimental setup

[0153] The method was implemented using a setup as shown in Fig. 1.

[0154] The CO2 was injected by a dual pump 6 (ISCO 250D), and the brine / surfactant solution was injected by a transfer vessel connected to a high- performance liquid chromatography (HPLC) pump 6’ (Waters 515 pump).

[0155] The back pressure and the confining pressure were controlled by two electrical back pressure regulators 4, 4’(BPRs) from Jasco (BP-4340).

[0156] The oxygen concentration in the solution exiting the core was monitored by a probe connected to an oxygen meter (PreSens GmbH).

[0157] The core was covered with two layers of shrinkable Teflon® tube and one layer of aluminum foil placed between the two Teflon® layers. The aluminum foil prevents the direct contact of CO2 with the Viton® rubber sleeve that is not compatible with supercritical CO2. The Teflon® layer protects the aluminum foil as under such harsh conditions the foil may be damaged after contact with high salinity brine.

[0158] An ultraviolet (UV) detector (UPC-900) was installed to measure the concentration of KI in the solution exiting the core during tracer tests. A pH probe was installed to monitor the pH of the solution exiting the core.

[0159] Pore volume measurement

[0160] The pore volume (PV) of the core was measured by the gas method at first. Then, the core was saturated with 3% NaCI brine under vacuum.

[0161] The pore volume measurement was performed to estimate core heterogeneity and pore volume, outside the setup to minimize dead volumes and pore volume estimation errors.

[0162] Tracer test

[0163] Then, the core was mounted in the setup of Fig. 1 and a tracer test was performed including all dead volumes that would be present during the subsequent surfactant injection.

[0164] In the tracer test, the test solution was injected to the core at a flow rate of 8.3 ft / day to establish a baseline profile at 25°C, with which the R-CADA concentration profile would be compared. This tracer test was performed five times.

[0165] Subsequently, the confining and back pressures were increased to 220 barg and 150 barg, respectively. The temperature of the oven was then increased to 110°C.

[0166] The properties of the core plug were determined as follows:

[0167] - Core pore volume (by gas method): 67.8 mL

[0168] - Core pore volume (by tracer test): 74.8 mL

[0169] - Dispersion coefficient: 1 .8 cm

[0170] - Core porosity by tracer test: 21 .9%

[0171] - Core water permeability: 139 mD

[0172] Surfactant solution injection

[0173] Then, 5% by volume CO2 and 0.2 wt.% R-CADA surfactant solution (CO2 solubility limit: 6.2%) in brine were co-injected into the core at a total flow rate of 4 ft / day, for about 6PV. The temperature was 110°C and the backpressure was 150 barg.

[0174] The pressure gradient during the injection was almost equal to continuous brine injection at the same flow rate (figure not shown), indicating that foam was not generated because all the CO2 was entirely solubilized in the aqueous phase. The solution samples exiting the core were collected every 0.05 PV for HPLC- CAD analysis. Results

[0175] Results of the tracer test and the surfactant solution injections are shown in Fig. 2. The concentration profiles of the test solution from five tracer tests exhibited similar patterns, forming a concentration profile A.

[0176] On average, the tracer concentration reached 50% (0.5) at approximately 0.95 to 1 PV.

[0177] According to the R-CADA concentration profile B, the R-CADA concentration reached 50% (0.5) after the injection of approximately 1 .75 PV, with a delay of about 0.75 PV relative to the tracer concentration, showing the adsorption of R-CADA on the core.

[0178] The pH (shown by crosses) of the solution exiting the core (after BPR) shows that the pH changed from 8.1 to 5.8 to 6.1 during the injection. At an early stage of the injection (between 0 to 1 PV), the pH was around 8.1 (at 20°C after CO2 degassing), and then still before the arrival of R-CADA (between 1 .0 to 1 .5 PV), the pH was about 6.8. This decrease was due to mixing with the water-in- place (pore space within the core that is filled with water).

[0179] At the end of the injection, the pH was about 5.7 and lower than the initial pH of brine (approximately 6.5).

[0180] Thus, good pH control in the core necessary for R-CADA solubility was achieved, owing to the CO2 dissolved in brine.

[0181] Calculation of the value of retention

[0182] The value of the retention was calculated according to the formula 1 (as described above):

[0183] Retention (mg / g of the core)

[0184] — ((PVs—PVT)pCs) / msample

[0185] = ((131 - 74.8)mL x 1 .1495 g / cm3x 2000 ppm) / (1000 mg / g x 670.08 g)

[0186] = 0.19 mg / g of core (0.19 ± 0.02 mg / g of core)

[0187] The PVs (injected volume of the surfactant solution) and PVT (injected volume of the test solution) were determined by multiplying 1.75 PV for the surfactant solution and 1 PV for the test solution by the pore volume of 74.8 mL, as measured by the test solution).

[0188] To convert the value from mg / g of rock to mg / m2of rock surface, the obtained value was divided by the Estaillades specific surface area (0.46±0.01 m2 / g of core), and determined to be 0.42 ± 0.04 mg / m2of rock surface.

[0189] In this experiment, the core sample was substantially devoid of oil and the R-CADA surfactant was entirely dissolved in the solution (because R-CADA is soluble in water at acidic pH). Thus, this value of retention corresponded to the value of adsorption.

[0190] The above results indicate that, considering the dispersion of the core sample, 2 PV of R-CADA solution at 0.2 wt.% must be injected to compensate for the adsorption and reach the critical surfactant concentration of 0.2 wt.% on Estaillades. This quantity is necessary to reach the maximum foam strength, although it is understood that the foam generates and develops much earlier with kinetics depending on porous media.

Claims

CLAIMS1. A method for determining a value of retention of a surfactant in a subterranean formation, comprising steps of:- injecting a flow of a solution comprising water, the surfactant and CO2 into a subterranean formation or a sample thereof, wherein the subterranean formation comprises a carbonate mineral, and wherein the CO2 is substantially entirely dissolved in the solution, the content of the dissolved CO2 in the solution being at least 50% of the solubility limit of CO2 in the solution;- collecting a flow of solution exiting the subterranean formation or the sample thereof; and- measuring the concentration of the surfactant in the flow of solution exiting the subterranean formation or the sample thereof.

2. The method of claim 1 , wherein the sample of the subterranean formation is a core from the subterranean formation, and the method further comprises a preliminary step of heating the core to a temperature T and pressurizing the core to a pressure P, wherein the temperature T and the pressure P are representative of natural conditions within the subterranean formation.

3. The method of claim 2, wherein the temperature T ranges from 30 to 200°C and the pressure P ranges from 2 to 250 barg.

4. The method of claim 2 or 3, wherein the pressure is controlled via a back pressure regulator.

5. The method of claim 1 , wherein the step of injecting the flow of the solution is performed via at least one injection well in the subterranean formation, and the step of collecting the flow of solution is performed via the injection well or via at least one production well in the subterranean formation.

6. The method of any one of claim 1 to 5, wherein the solution is a brine solution.

7. The method of any one of claims 1 to 6, wherein the subterranean formation comprises at least 5% by weight of the carbonate mineral.

8. The method of any one of claims 1 to 7, wherein the injecting step comprises co-injecting a flow of liquid, supercritical or gaseous CO2 and a flow of a solution comprising water and the surfactant into the subterranean formation or sample thereof at temperature T and pressure P, wherein the liquid, supercritical or gaseous CO2 substantially or fully dissolves in the solution at temperature T and pressure P, thereby not generating a foam.

9. The method of any one of claims 1 to 8, wherein the surfactant is soluble in water at acidic pH.

10. The method of claim 9, wherein the surfactant is a cationic surfactant.

11. The method of any one of claims 1 to 10, wherein the flow of the solution comprises or is a single-phase flow.

12. The method of any one of claims 1 to 11 , wherein the retention is adsorption of the surfactant in the subterranean formation or sample.

13. The method of any one of claims 1 to 12, wherein the content of the dissolved CO2 in the solution is at least 80%, preferably at least 90%, more preferably at least 95% of the solubility limit of CO2 in the solution.

14. The method of any one of claims 1 to 13, wherein the content of the dissolved CO2 in the solution is at least 0.01 mol / kg of the solution, preferably at least 0.03 mol / kg, more preferably at least 0.05 mol / kg, ideally at least 0.08 mol / kg.

15. The method of any one of claims 1 to 14, wherein the flow exiting the subterranean formation or sample thereof has a pH of from 3 to 8.

16. The method of any one of claim 1 to 15, wherein the subterranean formation or sample thereof comprises less than 20% of oil, preferably is substantially devoid of oil.

17. The method of any one of claims 1 to 16, further comprising a step of injecting a flow of a test solution comprising a non-reactive agent into the subterranean formation or sample thereof, and measuring the concentration of the non-reactive agent in the flow of the test solution exiting the subterranean formation or sample thereof.

18. The method of claim 17, comprising a step of comparing a concentration profile of the surfactant in the solution exiting the subterranean formation or sample thereof and a concentration profile of the non-reactive agent in the test solution exiting the subterranean formation or sample thereof, wherein the concentration profile is a function of cumulative injection of the solution.

19. The method of any one of claims 1 to 16, comprising a step of comparing the concentration of the surfactant in the solution to be injected into the subterranean formation or sample thereof and the concentration of the surfactant in the flow of solution exiting the subterranean formation or sample thereof.

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