Field of the Invention

[0001] The present invention relates to an oil in water emulsion to facilitate and optimize enhanced oil recovery and a method for designing an oil in water emulsion. The emulsion may be used as a drive fluid to displace and recover residual oil from a subterranean formation.

Background of the invention

[0002] Conventional oil production occurs in three phases: primary, secondary and tertiary. In the primary phase, natural pressure within the oil drives it towards the production wells and, with the help of pumps or other mechanisms, to the surface. Secondary production methods are typically based on water flooding where water is injected to the reservoir to increase the pressure and again drive the oil towards production wells. Enhanced Oil Recovery (EOR) is a tertiary method of oil recovery and can enable significant additional quantities of oil to be extracted. The aim of tertiary oil recovery methods is to reduce oil saturation by reducing viscosity of the oil remaining in the reservoir. Viscosity may be reduced through the application of heat or by injection of fluids that act as solvents. Typical EOR methods use injection of fluids through an injection well to "push" the oil towards production wells and can be classified as follows:

(a) Water flood, wherein water or brine is used as the injected fluid;

(b) Polymer flood, wherein polymer is added to the water or brine to increase its viscosity and therefore decrease the mobility ratio;

(c) Alkaline polymer floods, wherein the injected fluid is the same as polymer floods, but with caustic added. The caustic reacts with the acids present in the oil to form an in-situ surfactant, which in turns emulsifies the oil and improves transport through the porous medium. - -

The surfactant also helps reduce the interfacial tension at the oil water interface;

(d) Alkaline surfactant polymer (ASP) floods, wherein the fluid is the same as the polymer caustic flood, except that a surfactant is also added to decrease the interfacial tension of the oil/ water interface;

(e) Water-in-oil Emulsion floods, wherein the injected fluid is a water-in- oil emulsion; and

(f) Oil-in-water Emulsion floods, wherein the injected fluid is an oil-in- water emulsion.

[0003] Emulsion flooding is an effective EOR process for heavy oil reservoirs, where heavy oil lacks mobility under reservoir conditions and is not suitable for the application of thermal recovery methods because of environmental and economic issues or technical impediments. The present invention relates specifically to an oil in water emulsion for use in displacing and mobilizing hydrocarbons from a subterranean formation. The invention also relates to a method of using an oil-in-water emulsion flood to displace hydrocarbons from a subterranean formation.

[0004] Emulsion flooding for enhanced oil recovery was first proposed in 1973 by McAuliffe et al. (McAuliffe, C. D.: "Crude-Oil-in- Water Emulsion to Improve Fluid Flow in an Oil Reservoir," J Pet. Tech. (June 1973) 721- 726; McAuliffe, C D. "Oil-in- Water Emulsions and Their Flow Properties in Porous Media, "J. Pet. Tech. (June 1973), pp. 727-733.) McAuliffe et al concluded that the injection of a 0.4% pore volume slug of an oil-in-water emulsion containing 14% oil decreased fingering and increased volumetric sweep efficiency during water flooding that followed the emulsion slug injection. Another study by Ali et al ("Recovery Of Lloydminster and Morichal Crudes By Caustic, Acid And Emulsion Floods," The Journal of Canadian Petroleum (January- March 1979), pp. 53-59) also proposed the use of oil-in-water emulsion slugs as a flooding agent for heavy oil recovery.

[0005] In all of the studies mentioned above, caustic was used as the emulsifying agent. Caustic reacts with the naturally occurring acids in the - - crude oil to form in-situ surfactants. However, increasing the pH with caustic is often not practical or desirable when using field produced brine or field produced water in the emulsion, as increasing the pH results in precipitation of various inorganic salts and renders the brine unstable.

[0006] There has been some research performed on water-in-oil emulsion floods, for instance as described in R.D. Kaminsky et al., "Viscous Oil Recovery Using Solid-Stabilized Emulsion" SPE Paper 135284, 2010. Bragg et al. (US Patent No 5,910,404 and US Patent No. 5,910,467) describe using solids stabilised emulsions stabilised with microparticles and diluted with gas to displace viscous oils from a subterranean formation. However, microparticles can lead to pore plugging near the wellbore and thereby impact efficiency.

[0007] Various water in oil emulsions have been proposed for instance in Vadaraj (US Patent No.7, 186,673). However, often water-in oil emulsions exhibit viscosities in a range that is higher than the desired mobility ratio for a drive fluid.

[0008] Many emulsion flooding methods rely on instable emulsion systems, such that the emulsion breaks once in contact with the formation (for instance in Balzer et al (US 4,457,373) and Balzer (US Patent 4,582,138). In some cases reservoir conditions such as temperature and salinity levels may trigger the breaking of the emulsion.

[0009] Other emulsion flooding research has focused on use of microemulsions. Microemulsions are oil/water systems where both the oil and water form a continuous phase. For instance, Lepper (US Patent 4,488,602) discloses a process for emulsion flooding of petroleum reservoirs comprising injecting a microemulsion. However, microemulsions (also known as Winsor III systems) tend to be unstable when there are small changes in the environment such as temperature and salinity.

[0010] The emulsions of the present invention are termed "macroemulsions" (also known as Winsor I systems). Macroemulsions refer to oil-in water emulsions where the oil is distributed as small oil droplets - - within a water continuous phase or water-in oil emulsions where the water is distributed as small droplets within an oil continuous phase.

[0011] Another frequent issue in EOR, in particular, in heavy oil reservoirs, is that the mobility of the oil being recovered is significantly less than that of the drive fluid used to displace the oil. Mobility is defined by the ratio of the fluid's relative permeability to its viscosity. Ideally, an emulsion used as a drive fluid should have a low mobility ratio and lower than a water flood in all cases.

[0012] Accordingly, it is an object of the present invention to provide an emulsion that is stable throughout all stages of EOR and all flow conditions in the subterranean formation, including salinity, temperature and permeability. Also, it is important that the properties of the emulsion be compatible with the oil that is being recovered and the in-situ water.

[0013] It is also an object of the present invention to provide an improved tertiary oil recovery method using an oil in water emulsion, which method is observant of environmental concerns. The present invention satisfies this need.

Summary of the Invention

[0014] According to one aspect of the present invention there is provided an oil in water emulsion for use in producing hydrocarbons from a subterranean formation, said oil-in-water emulsion comprising an aqueous continuous phase and a hydrocarbon internal phase, said emulsion stabilized by a surfactant, wherein said surfactant has the following properties: (i) has an HLD that is less than 0; (ii) produces an emulsion wherein the interfacial tension between the hydrocarbon phase and the aqueous phase is less than about 5 mN/m, and (iii) does not phase separate at a temperature of from about 10° C to about 20°C above the formation temperature.

[0015] In another aspect of the present invention, there is provided an enhanced oil recovery method for producing hydrocarbons from a

subterranean formation comprising: - - a) providing a hydrocarbon phase and an aqueous medium for generating an oil-in-water emulsion;

b) selecting a surfactant to stabilize said emulsion, wherein said surfactant comprises the following properties: (i) has an HLD that is less than 0; (ii) produces an oil in water emulsion wherein the interfacial tension between the hydrocarbon phase and the aqueous liquid is less than about 5 mN/m, and (iii) does not phase separate at a temperature of from about 10° C to 20°C above the formation temperature;

c) generating the emulsion having a continuous phase formed from the aqueous phase and an internal phase formed from the hydrocarbon;

d) injecting the emulsion into a formation as a slug of fluid or as part of a drive fluid; and e) producing said hydrocarbons from the formation using the emulsion.

[0016] In yet a further aspect of the present invention, there is provided a method for preparing an oil-in-water emulsion comprising: combining water and a surfactant to form an aqueous solution; combining said aqueous solution with a hydrocarbon and mixing until said oil-in water emulsion is formed, wherein said surfactant comprises the following properties: (i) has an HLD that is less than 0; (ii) produces an emulsion wherein the interfacial tension between the hydrocarbon and the aqueous phase is less than about 5 mN/m; and (iii) does not phase separate at a temperature of from about 10° C to about 20°C above the formation temperature.

[0017] Water and oil are readily available at production sites, both in the form of produced water or produced brine and produced oil. This factor makes it very convenient and economical to use these as components of the emulsion. In addition, using produced water or produced brine has the added benefit of reducing the need for its disposal which often requires some form of pre-treatment prior to discharge to the environment. It also obviates the need to provide fresh water for preparing the emulsion which can be difficult and expensive, especially in remote areas. In a preferred embodiment the hydrocarbon that is used for the preparation of the emulsion is produced oil - - from the formation and the aqueous phase is produced water from the formation.

[0018] Unlike other emulsion flooding methods where the emulsion is prepared such that the emulsion breaks once in contact with the formation, the current invention relies on the emulsion to be stable throughout the flooding stages. Emulsion stability is the degree to which an emulsion retains its internal phase as droplets homogeneously distributed when the emulsion is stressed, for instance when an emulsion passes through porous media, or contacting the emulsion with a fluid of different salinity or pH. The careful selection and addition of a surfactant with a high affinity for water and that does not phase separate at a temperature of from 10° to about 20°C above the reservoir temperature, and which produces an emulsion wherein the interfacial tension between the hydrocarbon and the water is less than about 5 mN/m are amongst the factors which permit the emulsion described according to the present invention to remain stable throughout EOR.

[0019] In summary, it is believed that the emulsion flooding using an oil- in-water emulsion according to the present invention is effective, in part due to at least one of the following factors:

1) a decrease of interfacial tension at the oil/water interface because of the presence of surface active surfactants;

2) an increase in sweep efficiency of the flood by blocking main channels with bridging emulsion droplets due to their thixotropic flow characteristics at the pore throats where viscosity increases with shear rate;

3) a decrease in the viscosity difference between the injected fluid (emulsion) and the oil present in the reservoir (i.e., decrease of the mobility ratio); and

4) an increase in oil continuum from the injection to the production well by adsorption of the emulsion oil droplets onto reservoir oil deposits. - -

[0020] These and other features, aspects and advantages of the present invention will become better understood with regard to the following description.

Brief Description of the Drawings

[0021] The foregoing and other advantages may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which:

[0022] FIG.l depicts a graph comparing oil recovered and number of pore volumes injected into an exemplary core flood apparatus; and

[0023] FIG. 2 depicts a graph comparing oil recovered and number of pore volumes injected into an exemplary core flood apparatus.

Detailed description of the invention

[0024] The current invention relates to a novel method for enhancing oil recovery using an oil in water emulsion. The present invention also relates to a process for preparing an oil-in-water emulsion, and to the emulsions obtained thereby.

[0025] The invention may be practiced in various reservoir types, including sand or porous and fractured rock formations to extract naturally occurring hydrocarbons such as crude oil. The oil in the reservoir may be heavy or light typically having viscosities varying from about 1 to about 100,000 centipoise (cP). For instance, classes of oil are essentially based on viscosity and density of the material and are broken down as:

(i) Light Oil

45°>API>25°

Medium Heavy Oil

25°>API>18° - -

(ii) Extra Heavy Oil 20°>API>12°

(iii) Oil Sands and Bitumen 12°>API>6°

[0026] The term "oil", as used herein, comprises oil of any type or composition, including the classes mentioned above. Factors such as reservoir permeability and porosity will influence the penetration of the emulsion into the reservoir and the recovery of oil.

[0027] The oil-in-water emulsion of the present invention comprises a hydrocarbon, an aqueous medium and the use of a surfactant to emulsify and stabilise the emulsion. The emulsions relate to an oil-in-water emulsion where the oil is distributed as small oil droplets within a water continuous phase. Optionally, a polymer may be added to the oil-in-water emulsion, to increase its viscosity in certain applications.

[0028] The emulsions and methods of making such emulsions according to the present invention can be used as drive fluids to displace residual oils in a formation.

[0029] The hydrocarbon phase used for making the emulsion should preferably comprise of hydrocarbons previously produced from the same formation where the emulsion will be injected. The emulsions of the present invention are preferably used to recover moderately to extra heavy oils (12°<API<25°). In using the produced oil from the reservoir, compatibility between the injected fluid comprising the emulsion and the reservoir is maintained.

[0030] While it is preferable to use the same hydrocarbon as what is present in the reservoir to manufacture the emulsion, if desired, any other type of hydrocarbon could also be used, provided that its compatibility with the hydrocarbon in the formation is tested.

[0031] The produced oil may contain a variety of other components, such as brine or sand. Preferably, the hydrocarbon used for the emulsion - - manufacture must also be depleted of brine and sand. Typically, produced brine content in the hydrocarbon used for the emulsion can range from between about 0 to 15% by mass. Sand is usually not desirable because of the possibility of damaging the emulsification equipment, the well injection equipment and even the possibility of plugging the reservoir pores with new injected sand. Therefore, it is preferred that the hydrocarbon be treated to remove all sand via filtration or centrifugation methods or other methods known to those of ordinary skill in the art, including but not limited to mechanical separation, the use of heat and the use of chemicals .

[0032] The aqueous phase used for making the emulsion is preferably produced water from the formation and should have sufficient ion concentration to maintain stability of the emulsion under formation conditions. Preferably, the water contains at least 5000 ppm of dissolved solids. Produced water typically contains brine, dissolved solids, salts and minerals of sufficiently high content to require treatment prior to disposal in every day oil recovery operations. This invention allows for the disposal of the produced water back into the same reservoir, therefore eliminating the problems associated with the disposal of brine containing high salt concentration.

[0033] It is also an advantage of the present invention, to not have to reduce the divalent cation content of the brine prior to re-injecting it into a reservoir. Produced water used in this invention preferably will have gone through a minimal amount of processing. Typical processing should only consist of standard treating to separate the produced brine from the produced oil and a filtration step to remove sand and particulates, as known to one of ordinary skill in the art.

[0034] Another advantage of the present invention is that fresh water is not required for EOR. Emulsions described in the prior art requiring fresh water can be difficult to achieve as low salinity conditions are difficult to maintain since ionic species can dissolve from the rock causing breakdown of the emulsion. However, if fresh water is used as the aqueous phase according - - to the present invention, compatibility of the water is adjusted with that of the formation, for instance the ion concentration of the water, so that the emulsion stability is not affected. One method of adjusting ion concentration is adding salts, to the aqueous solution as needed for stabilising the emulsion under formation conditions.

[0035] The methods and compositions of this invention incorporate a surfactant to stabilise the oil-in-water emulsion. The surfactant is added to the hydrocarbon and water solution during the preparation of the emulsion. According to the invention, the chemical nature of the surfactant compound may be anionic, cationic, non-ionic, and/or amphoteric. Preferably, the surfactant that is used is a non-ionic surfactant.

[0036] Unlike other emulsion flooding methods where the emulsion is prepared such that the emulsion breaks once in contact with the formation (as in US patent 4,457,373 and 4,582,138, where the reservoir temperature triggers the breaking of the emulsion), the current invention relies on the emulsion to be stable throughout the flooding stages. Emulsion stability is the degree to which an emulsion retains its internal phase as droplets homogeneously distributed when the emulsion is stressed, for instance when an emulsion passes through porous media, or contacting the emulsion with a fluid of different salinity or pH.

[0037] In order to ensure emulsion stability, the surfactant is selected according to the oil and brine chemistries of the reservoir. The surfactant should have the following properties: (a) has an HLD value that is effective in producing an oil-in water emulsion; (b) does not phase separate at a temperature of from about 10°C to about 20° above the reservoir temperature; and (c) produce an interfacial tension that is less than about 5 mN/m at the oil water interface. Preferably, less than 1 mg of surfactant should adsorb onto lgram of formation rock.

[0038] The selection of a suitable surfactant is also based on the oil and brine chemistries of the hydrocarbon and aqueous phase, for example, by using well-known theories such as the HLD Theory of Jean-Louis Salager. - -

The HLD number (or Hydrophilic Lipophilic Deviation) of a surfactant is a well known quantity and needs no extended explanation herein. The reader is referred to J.L. Salager et al., "Principles of Emulsion Formulation Engineering," in Dinesh O. Shah and K . L Mittal, eds., Adsorption and Aggregation of Surfactants in Solution (CRC Press, 2002) 501-523. Using the HLD Theory and equations, the effects of the salts present in the aqueous phase (e.g. Na+, Ca2+, Mg2+, etc) can be predicted. For example, the salt content of the brine in the aqueous phase is known to affect the cloud point of non-ionic surfactants and sometimes will trigger precipitation of anionic surfactants. Such effects of salts are well-known and obvious to one choosing a certain surfactant for a certain application. In the foregoing and hereinafter, HLD means the equations described by J.L. Salager and for the reader's reference, the equations for non-ionic and ionic surfactants are reproduced below. The HLD equations for all other types of surfactants have not been reproduced below but are accessible by referring to Salager' s HLD Theory as described above.

[0039] The HLD of a surfactant, for a non-ionic surfactant is: HLD = a - EON - AACN - bS + aC _A + c (T- T _ref ) wherein EON is the average number of ethylene oxide groups per non-ionic surfactant molecule, ACN is the alkane carbon number, S is the salinity as wt% NaCl, CA is the alcohol concentration, T is the Temperature and a is a parameter that is characteristic of the surfactant lipophilic group type and branching. It increases linearly with the number of carbon atoms in the alkyl tail. The k, a, b, and c are numerical coefficients.

[0040] The HLD equation of a surfactant, for an ionic surfactant is:

HLD = σ + ln(S) - &ACN + c(T- T _ref ) + a A wherein σ is a parameter that is characteristic of the surfactant, S is the salinity as wt% NaCl, ACN is the alkane carbon number, T is the

temperature, and A is the percentage of alcohol added, k, c and a are numerical coefficients. - -

[0041] When the HLD > 0, a Winsor type II phase behaviour is exhibited and it is the oil the phase that contains most of the surfactant. At HLD = 0 formulation, the affinity of the surfactant is the same for both phases and a very low minimum of interfacial tension is exhibited. When the HLD <0 the affinity of the surfactant for the aqueous phase dominates, and a so-called Winsor type I phase behaviour is exhibited in which a surfactant-rich aqueous phase is in equilibrium with an essentially pure oil phase.

[0042] As such, it is recommended that a surfactant with an HLD of less than zero is selected for use in the present invention.

[0043] Interfacial tension is a measure of the ability of a liquid-liquid interface to deform. Different surfactants affect the interfacial tension differently. Typical surfactants used in surfactant based emulsion floods according to the prior art, will decrease the interfacial tension from >10mN/m to <0.01mN/m. The surfactants used with the present invention reduce the interfacial tension from >10mN/m to less than about 5mN/n, however the interfacial tension is preferably maintained above >0.01 mN/m. The reduction in interfacial tension provides stability to the emulsion, however the interfacial tension cannot be lowered too much or the emulsion will become unstable. The objective is to maintain the emulsion stable through the flood.

[0044] In order to maintain a low interfacial tension at the oil/water interface of less than about 5 mN/m, the selected surfactant should not phase separate at a temperature of from about 10° C to about 20° C above the formation temperature. This is another property which allows the emulsion according to the present invention to be stable, as surfactants tend to become less soluble with increasing temperature. The "formation temperature" is defined as the temperature of fluids resident in a formation rather than the operating temperature of the formation, which can vary depending on operating conditions such as heated fluids being injected into a reservoir.

[0045] Surfactant adsorption is an important feature governing the economic viability of an EOR flooding process. Typically surfactant adsorption on formation rock leads to gradual breakdown of an emulsion. - -

The most desirable surfactant is one that does not adsorb at all; however, such surfactants may not be effective as oil-recovery agents. Therefore, it is preferable that the surfactant is chosen from a family of surfactants such that less than 1 mg of surfactant adsorbs onto 1 gram of substrate.

[0046] In a preferred embodiment, a non-ionic surfactant is used. Examples of non-ionic surfactants that could be considered for the oil-in- water emulsion of the present invention include and are not limited to:

Nonyl phenol polyethoxylate

Linear alcohol polyethoxylates

Caster oil polyethoxylates

Synthetic alcohol polyethoxylates

Synthetic alcohol polypropoxylate

[0047] It should be noted that sometimes, the polyethoxylate chain in some of the surfactants mentioned above is changed to a polypropoxylate chain to improve the surfactant's ability to stay dissolved in a highly concentrated brine. The selection of other typical non-ionic surfactant would be known to one familiar with the art.

[0048] A polymer may optionally be added to the aqueous medium prior to emulsification. A polymer may be used to increase the viscosity of the emulsion and therefore, also increase the mobility ratio between the oil in the formation and the injection fluid being used to flood the reservoir. A suitable polymer may be selected from the visco-elastic polymer family most commonly used for standard polymer floods and alkaline surfactant polymer (ASP) floods.

[0049] The emulsions of this invention are prepared by mixing an aqueous phase with the oil phase in any manner. The oil-in-water emulsion is typically manufactured using standard emulsification equipment, such as colloidal mills or static mixers. In a particularly preferred embodiment, the emulsions of the invention are prepared using colloidal mills because of their ease of use and their adaptability to different process conditions. However, - - different emulsification equipment and shearing devices could also be used, as would be known to one of ordinary skill in the art.

[0050] The oil in water emulsion is formed by adding the hydrocarbon to the aqueous medium, in small aliquots or continuously and placing the mixture in a colloidal mill for a time sufficient to disperse the oil as small droplets in the continuous aqueous phase. The hydrocarbon content may vary from 0.1% to 80%, however it is preferred to have an emulsion comprising about 5-30% volume percent hydrocarbon.

[0051] The desired particle size of the internal phase droplets will depend on the pore size in the formation. The objective is that individual emulsion droplets pass through the pores unimpeded. Preferred droplet size, is one third of the pore size in the formation, so that the emulsion droplets are not impeded in flow when they pass through such formation. Average pore size in a formation can be derived by performing permeability measurements, as known to a person skilled in the art. In an embodiment of the present invention, droplets can be sheared to achieve a desired size when making the emulsion.

[0052] If the step of adding a polymer is used, the polymer can be added to the water prior to emulsification or added directly to the oil-in water emulsion.

[0053] The oil in water emulsion can be used in several different tertiary oil recovery methods. For example, the emulsion of the present invention can be used as a drive fluid for displacing oil from a subterranean formation. The oil in water emulsion is prepared at the surface and a slug is then injected into the reservoir at an injection well. The oil-in-water emulsion then displaces the oil in the formation towards a production well.

[0054] The following laboratory test was conducted to demonstrate the effectiveness of the emulsion as a drive fluid for recovering residual oil from a formation. - -

Example 1

[0055] The emulsion flooding was tested in a core flood apparatus (2" diameter, 12" long). The core was filled with Ottawa sand, given a permeability of approximately 7D, which is typical of Alberta heavy oil fields. The core was saturated with 12 API dead oil from an Alberta heavy oil field. Primary and secondary recovery was simulated with injection of produced reservoir brine (80,000ppm) for an equivalent of 4 pore volumes (4 X ~120mL). The injection rate was fixed at 9 mL/hr.

[0056] After primary and secondary recovery, 0.5 pore volume of an oil- in-water emulsion containing 25% hydrocarbon, 1% NP-330 surfactant and water (for a total of 100%) was injected followed by another 0.5 pore volume of another oil-in-water emulsion containing 10% hydrocarbon, 0.4 % NP-330 and water (for a total of 100%) was injected. NP-330 is a non-ionic surfactant and a commercial product from Akzo Nobel. Use of such a surfactant needs to be screened for local consumption and possible environmental constraints.

[0057] The emulsion flood was then followed by brine flood until no significant additional oil was produced. Figure 1 represents the oil recovered. The oil injected during the emulsion flooding stage was subtracted at PV=4.7. As it can be seen in Figure 1, 13% of the oil recovered can be attributed to the emulsion flood.

- -

Example 2

[0058] An additional example was performed following the same procedure as Example 1 above; however for the emulsion flood, the surfactant concentration was decreased to 0.75% and 0.3 % for the first and second half pore volume respectively. The oil recovered during this example is depicted in Figure 2. During the first emulsion flood cycle, 10% of the oil was recovered. A second emulsion flood cycle identical to the first was performed. An additional 9% of oil was recovered during the second cycle. As in the previous example, the oil injected during the emulsion flood cycles was subtracted at PV=5.9 and PV=14.3 for the first and second emulsion flood cycle respectively. As can be seen from the foregoing, emulsion flooding can be successful.

[0059] Although embodiments of the invention have been described above, it is not limited thereto and it will be apparent to those skilled in the art that numerous modifications form part of the present invention insofar as they do not depart from the spirit, nature and scope of the claimed and described invention