Patent Application
20170247603
The present invention relates to a method of treating a hydrocarbon containing formation using a composition which comprises an internal olefin sulfonate (IOS) surfactant.
Hydrocarbons, such as oil, may be recovered from hydrocarbon containing formations (or reservoirs) by penetrating the formation with one or more wells, which may allow the hydrocarbons to flow to the surface. A hydrocarbon containing formation may have one or more natural components that may aid in mobilising hydrocarbons to the surface of the wells. For example, gas may be present in the formation at sufficient levels to exert pressure on the hydrocarbons to mobilise them to the surface of the production wells. These are examples of so-called “primary oil recovery”.
However, reservoir conditions (for example permeability, hydrocarbon concentration, porosity, temperature, pressure, composition of the rock, concentration of divalent cations (or hardness), etc.) can significantly impact the economic viability of hydrocarbon production from any particular hydrocarbon containing formation. Furthermore, the above-mentioned natural pressure-providing components may become depleted over time, often long before the majority of hydrocarbons have been extracted from the reservoir. Therefore, supplemental recovery processes may be required and used to continue the recovery of hydrocarbons, such as oil, from the hydrocarbon containing formation. Such supplemental oil recovery is often called “secondary oil recovery” or “tertiary oil recovery”. Examples of known supplemental processes include waterflooding, polymer flooding, gas flooding, alkali flooding, thermal processes, solution flooding, solvent flooding, or combinations thereof.
Methods of chemical Enhanced Oil Recovery (cEOR) are applied in order to maximise the yield of hydrocarbons from a subterranean reservoir. In surfactant cEOR, the mobilisation of residual oil is achieved through surfactants which generate a sufficiently low crude oil/water interfacial tension (IFT) to give a capillary number large enough to overcome capillary forces and allow the oil to flow.
Compositions and methods for cEOR utilising an internal olefin sulfonate (IOS) as surfactant are described in U.S. Pat. No. 4,597,879, U.S. Pat. No. 4,979,564, U.S. Pat. No. 5,068,043 and “Field Test of Cosurfactant-enhanced Alkaline Flooding”, Falls et al., Society of Petroleum Engineers Reservoir Engineering, 1994, pages 217-223. Normally, IOS surfactants for enhanced hydrocarbon recovery are transported to a hydrocarbon recovery location and stored at that location in the form of an aqueous solution containing for example 30 to 35 wt. % of the surfactant(s). At the hydrocarbon recovery location, such solution may be further diluted to for example a 0.05-2 wt. % solution, before it is injected into a hydrocarbon containing formation. By such dilution, an aqueous fluid is formed which fluid can be injected into the hydrocarbon containing formation.
As mentioned above, before an aqueous, IOS surfactant containing solution, is injected into a hydrocarbon containing formation it may be further diluted, generally at the location of the hydrocarbon containing formation. The water or brine used in such further dilution may originate from the (location of the) hydrocarbon containing formation (from which hydrocarbons are to be recovered) or from any other source. In a case where the hydrocarbon containing formation is located in the bottom of a sea, it would be convenient to be able to use sea water as such fluid for diluting the surfactant containing solution. Sea water, however, contains a relatively high concentration of divalent cations, such as Ca2+ and Mg2+ cations. Generally, said divalent cations may be present in water or brine originating from the hydrocarbon containing formation and/or generally in water or brine (from whatever source) which is used to inject the surfactant into the hydrocarbon containing formation. For example, sea water may contain 1,700 parts per million by weight (ppmw) of divalent cations and may have a salinity of 3.6 wt. %.
Thus, a surfactant containing composition, in particular an IOS surfactant containing composition, may have to withstand a relatively high concentration of divalent cations, as mentioned above, for example 50 ppmw or more. In general, and also at such a high concentration of divalent cations, the IOS surfactant should have an adequate aqueous solubility since the latter improves the injectability of the fluid comprising the surfactant composition to be injected into the hydrocarbon containing formation. Further, an adequate aqueous solubility reduces loss of surfactant through adsorption to rock within the hydrocarbon containing formation.
A problem associated with the above-mentioned high concentration of divalent cations, in a case where the pH, for example the pH of an injectable fluid obtained by diluting an IOS surfactant containing solution with sea water, is relatively high (for example higher than 8.0), is that salts containing such divalent cation (for example magnesium cation, Mg2+) and an anion which does not originate from the surfactant (for example hydroxide anion, OH−), precipitate out (for example as solid Mg(OH)2). Another example is the formation of calcium carbonate (CaCO3) precipitate through the reactions of HO−+HCO3—→H2O+CO32− and CO32−+Ca2+→CaCO3. The formation of such precipitates is disadvantageous in that surfactant may be lost together with such precipitate, and may therefore not be available for interaction with the crude oil. In addition, such precipitate may plug a reservoir and a hazy injection solution may give increased surfactant loss related to adsorption as the solution propagates through the reservoir. Therefore, in order to prevent such precipitates from being formed, the pH should not be too high.
In the present invention, it is an object to provide a method of treating a hydrocarbon containing formation using a composition which comprises an internal olefin sulfonate (IOS), wherein such measures are taken to prevent or minimize, at a high divalent cation concentration, the above-discussed precipitation of salts containing a divalent cation and an anion which does not originate from the surfactant, before, during and after injection into the hydrocarbon containing formation, of an injectable fluid comprising said IOS surfactant containing composition.
Surprisingly, it was found that the above-mentioned object can be achieved by providing an aqueous composition which comprises i) an internal olefin sulfonate (IOS) surfactant; ii) an acid which has a pKa between 4 and 12; and iii) the conjugate base of said acid, to the hydrocarbon containing formation.
Accordingly, the present invention relates to a method of treating a hydrocarbon containing formation, comprising:
a) providing an aqueous composition which comprises i) an internal olefin sulfonate (IOS) surfactant; ii) an acid which has a pKa between 4 and 12; and iii) the conjugate base of the acid mentioned under ii), to at least a portion of the hydrocarbon containing formation, by combining the aqueous composition with a hydrocarbon removal fluid to produce an injectable fluid, wherein the hydrocarbon removal fluid comprises 1) water and 2) divalent cations in a concentration of 50 or more parts per million by weight (ppmw), and injecting the injectable fluid into the hydrocarbon containing formation; and
b) allowing the surfactant from the injectable fluid to interact with the hydrocarbons in the hydrocarbon containing formation.
In the context of the present invention, in a case where a composition (including an injectable fluid) comprises two or more components, these components are to be selected in an overall amount not to exceed 100%.
While the method of the present invention and the composition or injectable fluid used in said method are described in terms of “comprising”, “containing” or “including” one or more various described steps and components, respectively, they can also “consist essentially of” or “consist of” said one or more various described steps and components, respectively.”.
Within the present specification, “substantially no” means that no detectible amount is present.
In the cEOR method of the present invention, the aqueous composition to be provided to the hydrocarbon containing formation comprises i) an internal olefin sulfonate (IOS) surfactant; ii) an acid which has a pKa between 4 and 12; and iii) the conjugate base of said acid.
The above-mentioned “acid which has a pKa between 4 and 12” may take part in the following equilibrium reaction:
HA+H2OA−+H3O+
wherein:
HA is the acid which has a pKa between 4 and 12;
A− is the conjugate base of said acid;
Ka=[A−][H3O+]/[HA], wherein [A−] means the molar concentration (in mol/l) of A−, and so on; and
pKa=−log10 Ka.
The acid denoted as “HA”, as illustrated above, is neutral. However, as further illustrated below, in the present invention the acid having a pKa between 4 and 12 may also be positively charged (for example: NH4+ in ammonium chloride) or negatively charged (for example: the dicarboxylate derivative of citric acid which is 2-hydroxypropane-1,2,3-tricarboxylic acid). For example, in the case of a positively charged acid, the above-mentioned equilibrium reaction may be:
HA++H2OA+H3O+
In the present invention, surprisingly and advantageously, by requiring the IOS surfactant in the aqueous composition to be combined with an acid which has a pKa between 4 and 12 and with the conjugate base of such acid, the precipitation of salts containing a divalent cation and an anion which does not originate from the surfactant, before, during and after injection into the hydrocarbon containing formation, of an injectable fluid comprising the IOS surfactant containing composition, is prevented or minimized (e.g. delayed in time) at a high divalent cation concentration.
Further, it has appeared that with the present invention there is no or little risk of so-called “undershooting” to a low pH, not even locally. Typically, upon sulfonation of the internal olefin and subsequent neutralization, the pH of the resulting aqueous IOS containing solution is of from 10 to 14 (as further described below). By only adding an acid having a pKa of 4 or lower, such as hydrochloric acid (HCl), to such solution, one runs the risk of “undershooting” and ending up with a pH which is too low (for example below 7). Such “undershooting” is caused by the acid-base titration curve for these acids (having a pKa of 4 or lower) neutralizing the base (for example NaOH) as contained in the aqueous IOS containing solution having a high pH. According to such acid-base titration curve, the pH drops significantly over a very small concentration range of the added acid. For example, in a case where HCl is added to neutralize NaOH, the pH may drop from about 11 to about 3 within only a very small concentration range for HCl.
During the manufacture of an internal olefin sulfonate there may be 3 stages: 1) reaction of the internal olefin with sulfur trioxide (SO3) in a “falling film stage”, 2) neutralization with sodium hydroxide in a “neutralizer stage”, and 3) stabilization of the final product mixture in a “hydrolyser stage”. It is envisaged within the present invention that the adjustment of the high pH of the internal olefin sulfonate to a lower value as described above is performed after the hydrolyser stage, as a finishing step of the internal olefin sulfonate. Alternatively, it is envisaged within the present invention that the pH of the surfactant containing fluid (containing the internal olefin sulfonate) to be injected into the hydrocarbon containing formation is adjusted.
Instead of adding an acid which has a pKa between 4 and 12, a possible alternative method is to manufacture the internal olefin sulfonate with a low pH (e.g. pH 7-8) by reducing the amount of sodium hydroxide used during the neutralization stage. However, this method disadvantageously runs the risk of incomplete neutralization of the sultones formed (see
In relation to internal olefin sulfonates, such “free oil” as mentioned above comprises any non-ionic, organic compounds that may be present in an internal olefin sulfonate product, like for example an internal olefin. A higher free oil content is disadvantageous in several aspects. Firstly, a higher free oil content is indicative of a low efficiency of the IOS preparation process. Secondly, a higher free oil content may result in a worse product end performance, in particular a lower aqueous solubility. Thirdly, a higher free oil content may result in a worse physical product stability, in particular an increased tendency towards phase separation resulting in multiple (organic and aqueous) phases.
In the present invention, the above issues are advantageously avoided or minimized by using an acid, which has a pKa between 4 and 12, and its conjugate base. In other, alternative cases, where such acid and its conjugate base are not used, substantial disadvantages would arise. For example, in a case where only an acid having a pKa of 4 or lower is used, one would have to apply the following risky and time-consuming procedure: a) slow, stepwise titration (addition) of the acid to neutralise the base in the IOS containing solution; b) efficient mixing for full homogeneity at each step to avoid acid “hot spots” which could result in material corrosion issues, and c) checking the pH of the resulting mixture at each stage (step) to ensure that the pH of the solution would not become too low (for example drop below pH=7). Further, in a second case wherein a reduced sodium hydroxide level would be used in the neutralizer stage, there are potential product quality and material corrosion issues as discussed above.
The acid to be used in the present invention has a pKa between 4 and 12. In the present invention, said pKa is the pKa as measured at a temperature of 20° C. and under atmospheric pressure. The pKa of the acid to be used in the present invention is at least 4, or may be at least 5 or at least 6 or at least 7. Further, the pKa of said acid is at most 12, or may be at most 11 or at most 10 or at most 9. Suitably, the pKa of said acid is of from 5 to 12, and may be of from 6 to 12, or of from 6 to 11, or of from 6 to 10, or of from 6 to 9. Generally, it is preferred that the pKa of the acid having a pKa between 4 and 12 is lower than the pH of the aqueous IOS surfactant containing composition to which said acid may be added.
In the present invention, any acid having a pKa between 4 and 12 may be used. The acid may be organic or inorganic. For example, suitable acids having a pKa between 4 and 12 are listed at pages D-161 to D-165 in the following publication: “CRC Handbook of Chemistry and Physics”, 1989-1990, 70th edition, CRC Press, Inc. An example of an organic acid having a pKa between 4 and 12 which can suitably be used in the present invention, is ascorbic acid.
Organic acids having a pKa between 4 and 12 which can suitably be used in the present invention comprise any amine-acid complexes having a pKa between 4 and 12, for example an amine-acid complex of the formula (NR3)y.acid having a pKa between 4 and 12, wherein:
none, one, two or all of the three R moieties is or are hydrogen and none, one, two or all of the three R moieties is or are an alkyl group, which alkyl group may contain 1 to 20 carbon atoms, suitably 1 to 10 carbon atoms, and which alkyl group may be unsubstituted or substituted, in particular substituted by one or more heteroatom containing groups such as a hydroxyl group (—OH), a keto group (═O), an amine group (—NH2), a carboxylic acid group (—C(O)OH) or a carboxylate group (—C(O)O−);
y is equal to the number of acidic protons in the acid; and
the acid may be an acid having a pKa of 4 or lower, for example hydrocloric acid (HCl) and sulfuric acid (H2SO4).
Suitable examples of the above-mentioned amine-acid complex of the formula (NR3)y.acid include:
1) ammonium chloride: NH3.HCl (or NH4Cl)
2) ammonium sulfate: (NH3)2.H2SO4 (or (NH4)2SO4)
3) complex of ethanolamine and HCl: HOCH2CH2NH2.HCl
4) complex of diethanolamine and HCl: (HOCH2CH2)2NH.HCl
5) complex of triethanolamine and HCl: (HOCH2CH2)3N.HCl
In a case where an amine group containing compound as described above has 2 or more amine groups (polyamine) instead of just 1 amine group, multiple complexes of the above-described acid with the 2 or more amine groups in the same polyamine molecule may be formed. These 2 or more amine groups may be primary and/or secondary amine groups. In a case where the resulting complex has a pKa between 4 and 12, it may also suitably be used in the present invention. A suitable example is the complex of hydrogen chloride with ethylene diamine, which can be represented as HCl.NH2CH2CH2NH2.HCl (ethylene diamine.2HCl). Other suitable examples are the complexes of hydrogen chloride with triethylene tetramine (NH2CH2CH2NHCH2CH2NHCH2CH2NH2) or tetraethylene pent amine.
Another class of organic acids having a pKa between 4 and 12 which can suitably be used in the present invention comprises aliphatic acids which contain 1 or more carboxylic acid (—CO2H) groups and optionally 1 or more carboxylate (—CO2−) groups and which have a pKa between 4 and 12. Within the present specification, “aliphatic” means “non-aromatic”.
Said aliphatic acid may have 1 to 15 carbon atoms, suitably 2 to 10 carbon atoms, more suitably 2 to 8 carbon atoms, including the carbon atoms from the carboxylic acid and carboxylate groups. Further, said aliphatic acid may be substituted with one or more substituents other than a carboxylic acid or carboxylate group. Suitable other substituents are hydroxyl (—OH), keto (═O) and amine (—NH2), preferably hydroxyl. Said aliphatic acid may comprise 1 to 3, preferably 2 to 3, more preferably 3 carboxylic acid and carboxylate groups. Still further, said aliphatic acid may contain one or more carbon-carbon double bonds, that is to say it may be saturated or unsaturated.
Suitable examples of said aliphatic acid having a pKa between 4 and 12 are the monocarboxylate derivative of maleic acid and the dicarboxylate derivative of citric acid. The dicarboxylate derivative of citric acid is preferred.
Further, any inorganic acids having a pKa between 4 and 12 can also suitably be used in the present invention, for example:
1) Bicarbonate, HCO3−, as in sodium bicarbonate.
2) Boric acid, B(OH)3.
3) Dihydrogen phosphate, H2PO4−, as in sodium dihydrogen phosphate.
Preferably, in the present invention, the aqueous solubility of the acid having a pKa between 4 and 12 and the aqueous solubility of its conjugate base are sufficiently high, both in the IOS surfactant containing aqueous composition and in the injectable fluid that may be produced from such aqueous composition.
Further, preferably in the present invention, the molar ratio of the total molar amount of the acid having a pKa between 4 and 12 and its conjugate base to the molar amount of the IOS surfactant is of from 0 to 5, or may be of from 0.01 to 2 or of from 0.05 to 1.5 or of from 0.1 to 1 or of from 0.15 to 0.5.
Further, the aqueous composition to be used in the cEOR method of the present invention, comprises an internal olefin sulfonate (IOS) surfactant. Said composition may comprise one or more internal olefin sulfonates.
In the present invention, the surfactant composition contains water. That is to say, the surfactant composition is an aqueous surfactant composition. The active matter content of such aqueous surfactant composition is preferably at least 20 wt. %, more preferably at least 40 wt. %, more preferably at least 50 wt. %, most preferably at least 60 wt. %. “Active matter” herein means the total of anionic species in said aqueous composition, but excluding any inorganic anionic species like for example sodium sulfate. Said active matter content concerns the active matter content of the surfactant composition of the present invention before it is combined with the hydrocarbon removal fluid to produce an injectable fluid, which injectable fluid is injected into a hydrocarbon containing formation in accordance with the method of the present invention.
It may be desired to provide surfactant compositions which, when injected into a reservoir, may have an improved cEOR performance at a relatively high temperature and at a relatively high concentration of divalent cations, such as Ca2+ and Mg2+ cations. In practice, the temperature in a hydrocarbon containing formation may be as high as 60° C. or even higher. Further, said divalent cations may be present in water or brine originating from the hydrocarbon containing formation and/or generally in water or brine (from whatever source) which is used to inject the surfactant into the hydrocarbon containing formation. For example, sea water may contain 1,700 parts per million by weight (ppmw) of divalent cations and may have a salinity of about 3.6 wt. %.
In general, surfactant stability at a high temperature is relevant in order to prevent a surfactant from being decomposed at such high temperature. Internal olefin sulfonates (IOS) are known to be heat stable at a high temperature, for example up to 140-200° C. However, in addition to being heat stable, a surfactant composition may also have to withstand a relatively high concentration of divalent cations, as mentioned above, for example 50 ppmw or more. For such a high concentration of divalent cations may have the effect of precipitating the surfactant out of solution. In general, and in particular at such a high concentration of divalent cations, the surfactant should have an adequate aqueous solubility since the latter improves the injectability of the fluid comprising the surfactant composition to be injected into the hydrocarbon containing formation. Further, an adequate aqueous solubility reduces loss of surfactant through adsorption to rock or surfactant retention as trapped, viscous phases within the hydrocarbon containing formation. Precipitated solutions would not be suitable as they would result in loss of surfactant during a flood and could also result in reservoir plugging.
Generally, and also in the present invention, it is preferred that in the case of such high concentration of divalent cations as described above, the IOS is used in combination with another surfactant, in particular a surfactant that is tolerant to divalent cations, more in particular an alcohol alkoxy sulfate (AAS). Such other surfactant may be added when making the IOS containing injectable fluid or may be added before transport to the hydrocarbon containing formation where such injectable fluid would be injected.
One solution to such problem of a high concentration of divalent cations as described above is water softening, that is to say removing the divalent cations from the water or brine that may originate from the hydrocarbon containing formation. However, this would require using energy intensive processes such as reversed osmosis and would entail significant capital expenditure.
Thus, it may be desirable to provide surfactant compositions which may have a suitable cEOR performance, for example in terms of reducing the interfacial tension (IFT), under the above-described conditions of high temperature and high divalent cation concentration whilst at the same time having an adequately high aqueous solubility (for the solution prepared before injection).
The surfactant composition of the present invention comprises an internal olefin sulfonate which comprises internal olefin sulfonate molecules. An internal olefin sulfonate molecule is an alkene or hydroxyalkane which contains one or more sulfonate groups. Examples of such internal olefin sulfonate molecules are shown in
Thus, the composition of the present invention comprises an internal olefin sulfonate. Said internal olefin sulfonate (IOS) is prepared from an internal olefin by sulfonation.
Within the present specification, an internal olefin and an IOS comprise a mixture of internal olefin molecules and a mixture of IOS molecules, respectively. That is to say, within the present specification, “internal olefin” as such refers to a mixture of internal olefin molecules whereas “internal olefin molecule” refers to one of the components from such internal olefin. Analogously, within the present specification, “IOS” or “internal olefin sulfonate” as such refers to a mixture of IOS molecules whereas “IOS molecule” or “internal olefin sulfonate molecule” refers to one of the components from such IOS. Said molecules differ from each other for example in terms of carbon number and/or branching degree.
Branched IOS molecules are IOS molecules derived from internal olefin molecules which comprise one or more branches. Linear IOS molecules are IOS molecules derived from internal olefin molecules which are linear, that is to say which comprise no branches (unbranched internal olefin molecules). An internal olefin may be a mixture of linear internal olefin molecules and branched internal olefin molecules. Analogously, an IOS may be a mixture of linear IOS molecules and branched IOS molecules.
An internal olefin or IOS may be characterised by its carbon number and/or linearity.
In case reference is made to an average carbon number, this means that the internal olefin or IOS in question is a mixture of molecules which differ from each other in terms of carbon number. Within the present specification, said average carbon number is determined by multiplying the number of carbon atoms of each molecule by the weight fraction of that molecule and then adding the products, resulting in a weight average carbon number. The average carbon number may be determined by gas chromatography (GC) analysis of the internal olefin.
Within the present specification, linearity is determined by dividing the weight of linear molecules by the total weight of branched, linear and cyclic molecules. Substituents (like the sulfonate group and optional hydroxy group in the internal olefin sulfonates) on the carbon chain are not seen as branches. The linearity may be determined by gas chromatography (GC) analysis of the internal olefin.
Within the present specification, “branching index” (BI) refers to the average number of branches per molecule, which may be determined by dividing the total number of branches by the total number of molecules. Said branching index may be determined by 1H-NMR analysis.
When the branching index is determined by 1H-NMR analysis, said total number of branches equals: [total number of branches on olefinic carbon atoms (olefinic branches)]+[total number of branches on aliphatic carbon atoms (aliphatic branches)]. Said total number of aliphatic branches equals the number of methine groups, which latter groups are of formula R3CH wherein R is an alkyl group.
Further, said total number of olefinic branches equals: [number of trisubstituted double bonds]+[number of vinylidene double bonds]+2*[number of tetrasubstituted double bonds]. Formulas for said trisubstituted double bond, vinylidene double bond and tetrasubstituted double bond are shown below. In all of the below formulas, R is an alkyl group.
Within the present specification, said average molecular weight is determined by multiplying the molecular weight of each surfactant molecule by the weight fraction of that molecule and then adding the products, resulting in a weight average molecular weight.
In the present invention, the surfactant composition comprises an internal olefin sulfonate (IOS). Preferably at least 40 wt. %, more preferably at least 50 wt. %, more preferably at least 60 wt. %, more preferably at least 70 wt. %, more preferably at least 80 wt. %, most preferably at least 90 wt. % of said IOS is linear. For example, 40 to 100 wt. %, more suitably 50 to 100 wt. %, more suitably 60 to 100 wt. %, more suitably 70 to 99 wt. %, most suitably 80 to 99 wt. % of said IOS may be linear. Branches in said IOS may include methyl, ethyl and/or higher molecular weight branches including propyl branches.
Further, preferably, said IOS is not substituted by groups other than sulfonate groups and optionally hydroxy groups. Further, preferably, said IOS has an average carbon number in the range of from 5 to 30, more preferably 10 to 30, more preferably 15 to 30, most preferably 17 to 28.
Still further, preferably, said IOS may have a carbon number distribution within broad ranges. For example, in the present invention, said IOS may be selected from the group consisting of C15-18 IOS, C19-23 IOS, C20-24 IOS, C24-28 IOS and mixtures thereof, wherein “IOS” stands for “internal olefin sulfonate”. That is to say, said IOS may be C15-18 IOS or C19-23 IOS or C20-24 IOS or C24-28 IOS or any mixture thereof. IOS suitable for use in the present invention include those from the ENORDET™ O series of surfactants commercially available from Shell Chemicals Company.
“C15-18 internal olefin sulfonate” (C15-18 IOS) as used herein means a mixture of internal olefin sulfonate molecules wherein the mixture has an average carbon number of from 16 to 17 and at least 50% by weight, preferably at least 65% by weight, more preferably at least 75% by weight, most preferably at least 90% by weight, of the internal olefin sulfonate molecules in the mixture contain from 15 to 18 carbon atoms.
“C19-23 internal olefin sulfonate” (C19-23 IOS) as used herein means a mixture of internal olefin sulfonate molecules wherein the mixture has an average carbon number of from 21 to 23 and at least 50% by weight, preferably at least 60% by weight, of the internal olefin sulfonate molecules in the mixture contain from 19 to 23 carbon atoms.
“C20-24 internal olefin sulfonate” (C20-24 IOS) as used herein means a mixture of internal olefin sulfonate molecules wherein the mixture has an average carbon number of from 20 to 23 and at least 50% by weight, preferably at least 65% by weight, more preferably at least 75% by weight, most preferably at least 90% by weight, of the internal olefin sulfonate molecules in the mixture contain from 20 to 24 carbon atoms.
“C24-28 internal olefin sulfonate” (C24-28 IOS) as used herein means a mixture of internal olefin sulfonate molecules wherein the mixture has an average carbon number of from 24.5 to 27 and at least 40% by weight, preferably at least 45% by weight, of the internal olefin sulfonate molecules in the mixture contain from 24 to 28 carbon atoms.
Further, for the internal olefin sulfonates which are substituted by sulfonate groups, the cation may be any cation, such as an ammonium, alkali metal or alkaline earth metal cation, preferably an ammonium or alkali metal cation.
An IOS molecule is made from an internal olefin molecule whose double bond is located anywhere along the carbon chain except at a terminal carbon atom. Internal olefin molecules may be made by double bond isomerization of alpha olefin molecules whose double bond is located at a terminal position. Generally, such isomerization results in a mixture of internal olefin molecules whose double bonds are located at different internal positions. The distribution of the double bond positions is mostly thermodynamically determined. Further, that mixture may also comprise a minor amount of non-isomerized alpha olefins. Still further, because the starting alpha olefin may comprise a minor amount of paraffins (non-olefinic alkanes), the mixture resulting from alpha olefin isomeration may likewise comprise that minor amount of unreacted paraffins.
In the present invention, the amount of alpha olefins in the internal olefin may be up to 5%, for example 1 to 4 wt. % based on total composition. Further, in the present invention, the amount of paraffins in the internal olefin may be up to 2 wt. %, for example up to 1 wt. % based on total composition.
Suitable processes for making an internal olefin include those described in U.S. Pat. No. 5,510,306, U.S. Pat. No. 5,633,422, U.S. Pat. No. 5,648,584, U.S. Pat. No. 5,648,585, U.S. Pat. No. 5,849,960, EP0830315B1 and “Anionic Surfactants: Organic Chemistry”, Surfactant Science Series, volume 56, Chapter 7, Marcel Dekker, Inc., New York, 1996, ed. H. W. Stacke.
In the sulfonation step, the internal olefin is contacted with a sulfonating agent. Referring to
In a next step, sulfonated internal olefin from the sulfonation step is contacted with a base containing solution. Referring to
Thus, referring to
The IOS may comprise at least 30% hydroxyalkane sulfonate molecules, up to 70% alkene sulfonate molecules and up to 15% di-sulfonate molecules. Suitably, the IOS comprises from 40% to 95% hydroxyalkane sulfonate molecules, from 5% to 50% alkene sulfonate molecules and from 0% to 10% di-sulfonate molecules. Beneficially, the IOS comprises from 50% to 90% hydroxyalkane sulfonate molecules, from 10% to 40% alkene sulfonate molecules and from less than 1% to 5% di-sulfonate molecules. More beneficially, the IOS comprises from 70% to 90% hydroxyalkane sulfonate molecules, from 10% to 30% alkene sulfonate molecules and less than 1% di-sulfonate molecules. The composition of the IOS may be measured using a mass spectrometry technique.
U.S. Pat. No. 4,183,867, U.S. Pat. No. 4,248,793 and EP0351928A1 disclose processes which can be used to make internal olefin sulfonates. Further, the internal olefin sulfonates may be synthesized in a way as described by Van Os et al. in “Anionic Surfactants: Organic Chemistry”, Surfactant Science Series 56, ed. Stacke H. W., 1996, Chapter 7: Olefin sulfonates, pages 367-371. The above-mentioned acid having a pKa between 4 and 12 is preferably added to the IOS surfactant containing solution after preparation of the internal olefin sulfonate. Generally, such preparation involves the following 3 stages: sulfonation, neutralization and hydrolysis. In said neutralization stage a base containing solution is added, and during said hydrolysis stage the contacting with said base containing solution is continued. Thus, it is preferred that said acid having a pKa between 4 and 12 is added upon completion of the hydrolysis stage of IOS manufacture. After said hydrolysis stage and before said acid is added, the aqueous IOS surfactant containing solution normally comprises 0.1 to 1 wt. % of an aqueous alkali metal hydroxide, such as sodium hydroxide, suitably 0.2 to 0.6 wt. %, more suitably 0.2 to 0.5 wt. %, and normally has a pH of from 10 to 14, suitably 11 to 14, more suitably 12 to 14. By adding said acid, the pH of said solution may be reduced, suitably to a pH of from 7 to 11, or 7 to 10 or 7 to 9, or 7 to 8.
In the present invention, it is also envisaged that first an acid having a pKa of 6 or lower (for example acetic acid which has a pKa of 4.8), preferably a relatively small amount of such acid, is added to the aqueous IOS surfactant containing solution, during and after which addition said solution is preferably mixed thoroughly. After such acid having a relatively low pKa has been added, an acid having a pKa between 6 and 12 (for example the dicarboxylate derivative of citric acid which has a pKa of 6.4) is added. Similarly, an acid having a pKa of 6 or lower, which may be converted into an acid having a pKa between 6 and 12, may be added. For example, the monocarboxylate derivative of citric acid (pKa=4.8) may be added which may be converted into the dicarboxylate derivative of citric acid (pKa=6.4) which in turn may be further converted into its conjugate base (tricarboxylate derivative of citric acid).
Still further, it is envisaged in the present invention that an acid is added which has a pKa of 4 or lower but which acid also has a deprotonated derivative having a pKa between 4 and 12. In this case, a relatively small amount of such acid having a pKa of 4 or lower may be added. Further, during and after said addition, the solution is preferably mixed thoroughly. For example, phosphoric acid (pKa=2.1) may be added which may be converted into dihydrogen phosphate (pKa=7.2) which in turn may be further converted into its conjugate base (monohydrogen phosphate).
In the present invention, a co-solvent (or solubilizer) may be added to increase the solubility of the surfactant(s) in the aqueous composition and/or in the below-mentioned injectable fluid comprising said composition used in the present cEOR method. Any amount of co-solvent needed to dissolve all of the surfactant at a certain salt concentration (salinity) may be easily determined by a skilled person through routine tests. Suitable co-solvents include low molecular weight alcohols and other organic solvents or combinations thereof.
Suitable low molecular weight alcohols for use as co-solvent include C1-C10 alkyl alcohols, more suitably C1-C8 alkyl alcohols, most suitably C1-C6 alkyl alcohols, or combinations thereof. Examples of suitable C1-C4 alkyl alcohols are methanol, ethanol, 1-propanol, 2-propanol (isopropyl alcohol), 1-butanol, 2-butanol (sec-butyl alcohol), 2-methyl-1-propanol (iso-butyl alcohol) and 2-methyl-2-propanol (tert-butyl alcohol). Examples of suitable C5 alkyl alcohols are 1-pentanol, 2-pentanol and 3-pentanol, and branched C5 alkyl alcohols, such as 2-methyl-2-butanol (tert-amyl alcohol). Examples of suitable C6 alkyl alcohols are 1-hexanol, 2-hexanol and 3-hexanol, and branched C6 alkyl alcohols
Suitable other organic solvents for use as co-solvent include methyl ethyl ketone, acetone, lower alkyl cellosolves, lower alkyl carbitols or combinations thereof.
Further, one or more compounds which under the conditions in a hydrocarbon containing formation may be converted into any of the above-mentioned co-colvents may be used, such as one or more of the above-mentioned low molecular weight alcohols. Such precursor co-solvent compounds may include ether compounds, such as ethylene glycol monobutyl ether (ELBE), diethylene glycol monobutyl ether (DCBE) and triethylene glycol monobutyl ether (TGBE). The latter 3 ether compounds may be converted under the conditions in a hydrocarbon containing formation into ethanol and 1-butanol.
Still further, polyethylene glycol and/or an alcohol ethoxylate may be used as co-solvent.
Thus, the present invention relates to a method of treating a hydrocarbon containing formation, comprising:
a) providing the above-described aqueous composition which comprises i) an IOS surfactant; ii) an acid which has a pKa between 4 and 12; and iii) the conjugate base of said acid, to at least a portion of the hydrocarbon containing formation, by combining the aqueous composition with a hydrocarbon removal fluid to produce an injectable fluid, wherein the hydrocarbon removal fluid comprises 1) water and
2) divalent cations in a concentration of 50 or more parts per million by weight (ppmw), and injecting the injectable fluid into the hydrocarbon containing formation; and
b) allowing the surfactant from the injectable fluid to interact with the hydrocarbons in the hydrocarbon containing formation.
In the present invention, the above-described aqueous composition is combined with a hydrocarbon removal fluid to produce an injectable fluid, suitably at the location of the hydrocarbon containing formation, after which the injectable fluid is injected into the hydrocarbon containing formation. Said hydrocarbon removal fluid comprises 1) water and 2) divalent cations in a concentration of 50 or more parts per million by weight (ppmw). It may also comprise monovalent cations. By said concentration of divalent cations reference is made to the concentration of divalent cations in the water (e.g. brine) in combination with which the above-described aqueous composition which comprises i) an IOS surfactant and ii) an acid which has a pKa between 4 and 12, is provided to at least a portion of the hydrocarbon containing formation. Said water may originate from the hydrocarbon containing formation or from any other source, such as river water, sea water or aquifer water. A suitable example is sea water which may contain 1,700 ppmw of divalent cations. Suitably, said divalent cations comprise calcium (Ca2) and magnesium (Mg2) cations. Further, preferably, said concentration of divalent cations is of from 50 to 25,000 ppmw. In practice, said concentration of divalent cations may vary strongly between different sources. In the present invention, said concentration of divalent cations is at least 50 ppmw, suitably at least 100 ppmw, more suitably at least 200 ppmw, more suitably at least 500 ppmw, more suitably at least 1,000 ppmw, more suitably at least 1,500 ppmw, more suitably at least 2,000 ppmw, most suitably at least 3,000 ppmw. Further, said concentration of divalent cations may be at most 25,000 ppmw, suitably at most 20,000 ppmw, more suitably at most 15,000 ppmw, more suitably at most 10,000 ppmw, suitably at most 8,000 ppmw, more suitably at most 6,000 ppmw, most suitably at most 5,000 ppmw.
Further, in the present invention, the salinity of said water (e.g. brine), which may originate from the hydrocarbon containing formation or from any other source, may be of from 0.5 to 30 wt. % or 0.5 to 20 wt. % or 0.5 to 10 wt. % or 1 to 6 wt. %. By said “salinity” reference is made to the concentration of total dissolved solids (% TDS), wherein the dissolved solids comprise dissolved salts. Said salts may be salts comprising divalent cations, such as magnesium chloride and calcium chloride, and salts comprising monovalent cations, such as sodium chloride and potassium chloride. Sea water may have a salinity (% TDS) of 3.6 wt. %.
Sea water may also contain a certain amount of an acid having a pKa between 4 and 12 and/or its conjugate base, for example bicarbonate/carbonate. In case such sea water is used to dilute the IOS surfactant containing aqueous composition thereby producing an injectable fluid, it is preferred that before forming such injectable fluid, the amount and/or type of the acid having a pKa between 4 and 12 and its conjugate base in said aqueous composition is/are such that in the injectable fluid the target pH may be achieved, thus taking into account the composition of the sea water.
In the method of the present invention, the temperature may be 25° C. or higher. By said temperature reference is made to the temperature in the hydrocarbon containing formation. Preferably, said temperature is of from 25 to 200° C., more preferably of from 25 to 150° C., most preferably of from 25 to 80° C. In practice, said temperature may vary strongly between different hydrocarbon containing formations.
In the present method of treating a hydrocarbon containing formation, in particular a crude oil-bearing formation, the surfactant which is a IOS surfactant is applied in cEOR (chemical Enhanced Oil Recovery) at the location of the hydrocarbon containing formation, more in particular by providing the above-described composition, via the above-mentioned injectable fluid, to at least a portion of the hydrocarbon containing formation and then allowing the surfactant from said composition to interact with the hydrocarbons in the hydrocarbon containing formation.
Normally, as also discussed in the introduction above, surfactants for enhanced hydrocarbon recovery are transported to a hydrocarbon recovery location and stored at that location in the form of an aqueous solution containing for example 30 to 35 wt. % of the surfactant(s). At the hydrocarbon recovery location, such solution would then be further diluted to a 0.05-2 wt. % solution, before it is injected into a hydrocarbon containing formation. By such dilution, an aqueous fluid is formed which fluid can be injected into the hydrocarbon containing formation, that is to say an injectable fluid. The water or brine used in such further dilution may originate from the hydrocarbon containing formation (from which hydrocarbons are to be recovered) or from any other source.
The total amount of the surfactant(s) in said injectable fluid may be of from 0.05 to 2 wt. %, preferably 0.1 to 1.5 wt. %, more preferably 0.1 to 1.0 wt. %, most preferably 0.2 to 0.7 wt. %.
In the present invention, the above-mentioned injectable fluid may also comprise a polymer as further described below. The polymer may be added to the injectable fluid, or to the surfactant containing aqueous composition before forming the injectable fluid. The main function of the polymer is to increase viscosity. In particular, the polymer may provide mobility control (relative to the oil phase) as the injectable fluid propagates from the injection well to the production well, and stimulate the formation of an oil bank that is pushed to such production well.
Thus, the polymer should be a viscosity increasing polymer. More in particular, in the present invention, the polymer should increase the viscosity of an aqueous fluid in which the aqueous surfactant containing composition has been dissolved, which aqueous fluid may then be injected into a hydrocarbon containing formation. For production from a hydrocarbon containing formation may be enhanced by treating the hydrocarbon containing formation with a polymer that may mobilise hydrocarbons to one or more production wells. The polymer may reduce the mobility of the water phase, because of the increased viscosity, in pores of the hydrocarbon containing formation. The reduction of water mobility may allow the hydrocarbons to be more easily mobilised through the hydrocarbon containing formation.
Suitable polymers performing the above-mentioned function of increasing viscosity in enhanced oil recovery, for use in the present invention, and preparations thereof, are described in U.S. Pat. No. 6,427,268, U.S. Pat. No. 6,439,308, U.S. Pat. No. 5,654,261, U.S. Pat. No. 5,284,206, U.S. Pat. No. 5,199,490 and U.S. Pat. No. 5,103,909, and also in “Viscosity Study of Salt Tolerant Polymers”, Rashidi et al., Journal of Applied Polymer Science, volume 117, pages 1551-1557, 2010.
Suitable commercially available polymers for cEOR include Flopaam® manufactured by SNF Floerger, CIBA® ALCOFLOOD® manufactured by Ciba Specialty Additives (Tarrytown, N.Y.), Tramfloc® manufactured by Tramfloc Inc. (Temple, Ariz.) and HE® polymers manufactured by Chevron Phillips Chemical Co. (The Woodlands, Tex.). A specific suitable polymer commercially available at SNF Floerger is Flopaam® 3630 which is a partially hydrolysed polyacrylamide.
The nature of the polymer is not relevant in the present invention, as long as the polymer can increase viscosity.
That is, the molecular weight of the polymer should be sufficiently high to increase viscosity. Suitably, the molecular weight of the polymer is at least 1 million Dalton, more suitably at least 2 million Dalton, most suitably at least 4 million Dalton. The maximum for the molecular weight of the polymer is not essential. Suitably, the molecular weight of the polymer is at most 30 million Dalton, more suitably at most 25 million Dalton.
Further, the polymer may be a homopolymer, a copolymer or a terpolymer. Still further, the polymer may be a synthetic polymer or a biopolymer or a derivative of a biopolymer. Examples of suitable biopolymers or derivatives of biopolymers include xanthan gum, guar gum and carboxymethyl cellulose.
A suitable monomer for the polymer, suitably a synthetic polymer, is an ethylenically unsaturated monomer of formula R1R2C═CR3R4, wherein at least one of the R1, R2, R3 and R4 substituents is a substituent which contains a moiety selected from the group consisting of —C(═O)NH2, —C(═O)OH, —C(═O)OR wherein R is a branched or linear C6-C18 alkyl group, —OH, pyrrolidone and —SO3H (sulfonic acid), and the remaining substituent(s), if any, is (are) selected from the group consisting of hydrogen and alkyl, preferably C1-C4 alkyl, more preferably methyl. Most preferably, said remaining substituent(s), if any, is (are) hydrogen. Suitably, a polymer is used that is made from such ethylenically unsaturated monomer.
Suitable examples of the ethylenically unsaturated monomer as defined above, are acrylamide, acrylic acid, lauryl acrylate, vinyl alcohol, vinylpyrrolidone, and styrene sulfonic acid and 2-acrylamido-2-methylpropane sulfonic acid. Suitable examples of ethylenic homopolymers that are made from such ethylenically unsaturated monomers are polyacrylamide, polyacrylate, polylauryl acrylate, polyvinyl alcohol, polyvinylpyrrolidone, and polystyrene sulfonate and poly(2-acrylamido-2-methylpropane sulfonate). For these polymers, the counter cation for the —C(═O)O− moiety (in the case of polyacrylate) and for the sulfonate moiety may be an alkali metal cation, such as a sodium ion, or an ammonium ion.
As mentioned above, copolymers or terpolymers may also be used. Examples of suitable ethylenic copolymers include copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, and lauryl acrylate and acrylamide.
Preferably, the polymer which may be used in the present invention is a polyacrylamide, more preferably a partially hydrolysed polyacrylamide. A partially hydrolysed polyacrylamide contains repeating units of both —[CH2—CHC(═O)NH2]— and —[CH2—CHC(═O)O−M+]— wherein M+ may be an alkali metal cation, such as a sodium ion, or an ammonium ion. The extent of hydrolysis is not essential and may vary within wide ranges. For example, 1 to 99 mole %, or 5 to 95 mole %, or 10 to 90 mole %, suitably 15 to 40 mole %, more suitably 20 to 35 mole %, of the polyacrylamide may be hydrolysed.
Hydrocarbons may be produced from hydrocarbon containing formations through wells penetrating such formations. “Hydrocarbons” are generally defined as molecules formed primarily of carbon and hydrogen atoms such as oil and natural gas. Hydrocarbons may also include other elements, such as halogens, metallic elements, nitrogen, oxygen and/or sulfur. Hydrocarbons derived from a hydrocarbon containing formation may include kerogen, bitumen, pyrobitumen, asphaltenes, oils or combinations thereof. Hydrocarbons may be located within or adjacent to mineral matrices within the earth. Matrices may include sedimentary rock, sands, silicilytes, carbonates, diatomites and other porous media.
A “hydrocarbon containing formation” may include one or more hydrocarbon containing layers, one or more non-hydrocarbon containing layers, an overburden and/or an underburden. An overburden and/or an underburden includes one or more different types of impermeable materials. For example, overburden/underburden may include rock, shale, mudstone, or wet/tight carbonate (that is to say an impermeable carbonate without hydrocarbons). For example, an underburden may contain shale or mudstone. In some cases, the overburden/underburden may be somewhat permeable. For example, an underburden may be composed of a permeable mineral such as sandstone or limestone.
Properties of a hydrocarbon containing formation may affect how hydrocarbons flow through an underburden/overburden to one or more production wells. Properties include porosity, permeability, pore size distribution, surface area, salinity or temperature of formation. Overburden/underburden properties in combination with hydrocarbon properties, capillary pressure (static) characteristics and relative permeability (flow) characteristics may affect mobilisation of hydrocarbons through the hydrocarbon containing formation.
Fluids (for example gas, water, hydrocarbons or combinations thereof) of different densities may exist in a hydrocarbon containing formation. A mixture of fluids in the hydrocarbon containing formation may form layers between an underburden and an overburden according to fluid density. Gas may form a top layer, hydrocarbons may form a middle layer and water may form a bottom layer in the hydrocarbon containing formation. The fluids may be present in the hydrocarbon containing formation in various amounts. Interactions between the fluids in the formation may create interfaces or boundaries between the fluids. Interfaces or boundaries between the fluids and the formation may be created through interactions between the fluids and the formation. Typically, gases do not form boundaries with other fluids in a hydrocarbon containing formation. A first boundary may form between a water layer and underburden. A second boundary may form between a water layer and a hydrocarbon layer. A third boundary may form between hydrocarbons of different densities in a hydrocarbon containing formation.
Production of fluids may perturb the interaction between fluids and between fluids and the overburden/underburden. As fluids are removed from the hydrocarbon containing formation, the different fluid layers may mix and form mixed fluid layers. The mixed fluids may have different interactions at the fluid boundaries. Depending on the interactions at the boundaries of the mixed fluids, production of hydrocarbons may become difficult.
Quantification of energy required for interactions (for example mixing) between fluids within a formation at an interface may be difficult to measure. Quantification of energy levels at an interface between fluids may be determined by generally known techniques (for example spinning drop tensiometer). Interaction energy requirements at an interface may be referred to as interfacial tension. “Interfacial tension” as used herein, refers to a surface free energy that exists between two or more fluids that exhibit a boundary. A high interfacial tension value (for example greater than 10 mN/m) may indicate the inability of one fluid to mix with a second fluid to form a fluid emulsion. As used herein, an “emulsion” refers to a dispersion of one immiscible fluid into a second fluid by addition of a compound that reduces the interfacial tension between the fluids to achieve stability. The inability of the fluids to mix may be due to high surface interaction energy between the two fluids. Low interfacial tension values (for example less than 1 mN/m) may indicate less surface interaction between the two immiscible fluids. Less surface interaction energy between two immiscible fluids may result in the mixing of the two fluids to form an emulsion. Fluids with low interfacial tension values may be mobilised to a well bore due to reduced capillary forces and subsequently produced from a hydrocarbon containing formation. Thus, in surfactant cEOR, the mobilisation of residual oil is achieved through surfactants which generate a sufficiently low crude oil/water interfacial tension (IFT) to give a capillary number large enough to overcome capillary forces and allow the oil to flow.
Mobilisation of residual hydrocarbons retained in a hydrocarbon containing formation may be difficult due to viscosity of the hydrocarbons and capillary effects of fluids in pores of the hydrocarbon containing formation. As used herein “capillary forces” refers to attractive forces between fluids and at least a portion of the hydrocarbon containing formation. Capillary forces may be overcome by increasing the pressures within a hydrocarbon containing formation.
Capillary forces may also be overcome by reducing the interfacial tension between fluids in a hydrocarbon containing formation. The ability to reduce the capillary forces in a hydrocarbon containing formation may depend on a number of factors, including the temperature of the hydrocarbon containing formation, the salinity of water in the hydrocarbon containing formation, and the composition of the hydrocarbons in the hydrocarbon containing formation.
As production rates decrease, additional methods may be employed to make a hydrocarbon containing formation more economically viable. Methods may include adding sources of water (for example brine, steam), gases, polymers or any combinations thereof to the hydrocarbon containing formation to increase mobilisation of hydrocarbons.
In the present invention, the hydrocarbon containing formation is thus treated with a surfactant(s) containing injectable fluid, as described above. Interaction of said fluid with the hydrocarbons may reduce the interfacial tension of the hydrocarbons with one or more fluids in the hydrocarbon containing formation. The interfacial tension between the hydrocarbons and an overburden/underburden of a hydrocarbon containing formation may be reduced. Reduction of the interfacial tension may allow at least a portion of the hydrocarbons to mobilise through the hydrocarbon containing formation.
The ability of the surfactant(s) containing injectable fluid to reduce the interfacial tension of a mixture of hydrocarbons and fluids may be evaluated using known techniques. The interfacial tension value for a mixture of hydrocarbons and water may be determined using a spinning drop tensiometer. An amount of the surfactant(s) containing injectable fluid may be added to the hydrocarbon/water mixture and the interfacial tension value for the resulting fluid may be determined.
The surfactant(s) containing injectable fluid may be provided (for example injected) into hydrocarbon containing formation 100 through injection well 110 as depicted in
The surfactant(s) from the surfactant(s) containing injectable fluid may interact with at least a portion of the hydrocarbons in hydrocarbon layer 130. This interaction may reduce at least a portion of the interfacial tension between one or more fluids (for example water, hydrocarbons) in the formation and the underburden 140, one or more fluids in the formation and the overburden 120 or combinations thereof.
The surfactant(s) from the surfactant(s) containing injectable fluid may interact with at least a portion of hydrocarbons and at least a portion of one or more other fluids in the formation to reduce at least a portion of the interfacial tension between the hydrocarbons and one or more fluids. Reduction of the interfacial tension may allow at least a portion of the hydrocarbons to form an emulsion with at least a portion of one or more fluids in the formation. The interfacial tension value between the hydrocarbons and one or more other fluids may be improved by the surfactant(s) containing injectable fluid to a value of less than 0.1 mN/m or less than 0.05 mN/m or less than 0.001 mN/m.
At least a portion of the surfactant(s) containing injectable fluid/hydrocarbon/fluids mixture may be mobilised to production well 150. Products obtained from the production well 150 may include components of the surfactant(s) containing injectable fluid, methane, carbon dioxide, hydrogen sulfide, water, hydrocarbons, ammonia, asphaltenes or combinations thereof. Hydrocarbon production from hydrocarbon containing formation 100 may be increased by greater than 50% after the surfactant(s) containing injectable fluid has been added to a hydrocarbon containing formation.
The surfactant(s) containing injectable fluid may also be injected into hydrocarbon containing formation 100 through injection well 110 as depicted in
