The invention relates to improved methods for advanced oil extraction and in particular to a particular mode of applying an electric current in order to optimize the yield of oil to be extracted from an oil-bearing earth formation. 2. Prior art

The extraction of crude oil usually involves the use oil wells, if the oil is not located just below the earth's surface such that it can be recovered in open cast mining. There are three stages at which the oil is recovered from the production well. At the primary recovery stage, the oil is sufficiently available and initially also under pressure that it may either just be collected by drilling into the oil-bearing earth formation or by the use of pumps once the natural pressure is no longer sufficient anymore. At the secondary recovery stage, the natural reservoir drive is no longer sufficient to allow for effective pumping. Now, water or immiscible gas is injected into the reservoir via another, remote injection well in order to provide both, pressure maintenance and increase the viscosity of the displacing fluid to aid extracting some of the remaining crude oil (so-called water or gas flooding). The water or gas injected via the injection well drives the oil towards the production well.

After oil recovery at the secondary stage, oil still remains in the earth formation, for example, as it is trapped in the pores of the rock. Also, the wettability of the earth formation is an important factor. Wettability is defined as the tendency of one fluid to spread on, or adhere to, a solid surface in the presence of other immiscible fluids, Yefei, W. et al., Petroleum Science (2011), Vol. 8, Issue 4, pp 463-476. In an oil-wet formation, the oil adheres strongly to the rock making it difficult to recover. At the same time, water e.g. during water flooding, cannot penetrate the rock due to the existing high interfacial tension (IFT) of the two fluids. Thus the water cannot properly displace the oil contained in said formation.

Now, at the tertiary recovery stage using enhanced oil recovery (EOR) techniques, residual oil remaining in the formation due to the above reasons may still be depleted from the reservoir to a certain extent. EOR techniques comprise inter alia (further) reducing the viscosity of the oil using for example hot water steam, C0 ₂ , N ₂ or petroleum gas. Likewise, the mechanical driving force of the water on the oil can be increased by adding water-soluble polymers to the water. This is called "polymer flooding". It is also possible to reduce the surface tension of the oil by adding surfactants (surfactant flooding) or by adding nanoparticles (nano flooding) to the water. Likewise the pores in, for example, lime containing rock can be opened or widened by adding acids to the water to be introduced. Another technique used for secondary oil recovery as well as during EOR is the application of direct electric current (DC) through the oil-bearing earth formation. While the cathode is placed at or near the production well, one or more anodes are placed at some distance from the production well for example at the injection well to create an electric field.

This method is in particular described to enhance oil production from carbonate reservoirs, cf. WO 2012/074510. Several mechanisms of action are described that promote the recovery of oil by use of such an electric field. One effect is electroosmotic pressure; the formation water is pulled through the oil sand in the direction of the producing well, cf. US 3,782,465. Similarly, electrolytes dissolved in the connate water and other suspended charged particles migrate through the oil toward a cathode, carrying oil molecules with them, cf. US 6,877,556. The latter effect can be increased by supplementing the injected water with charged molecules like electrolytes, cf.

US 3,782,465.

Another described effect of the DC treatment is that the wettability of e.g. a carbonate rock surface is altered and that the IFT between oil and water is reduced. Specifically, the carbonate rock surface is rendered more hydrophilic than before electrokinetic treatment, thereby causing oil to be more easily displaced from the rock surface, e.g., by water flooding, cf. WO 2012/074510.

Nevertheless, the use of electrokinetics in EOR as described in the art is accompanied by several disadvantages. First, the use of a current is costly. Second, the constant application of current also negatively effects the EOR process itself for several reasons. For example, the electric current may degrade a surfactant that was injected into the formation thus reducing its desired effect. Also, nanoparticles are constantly "pulled" towards the cathode/production well, which may lead to a blockage of the pores in the formation, as the pores of the oil-bearing earth formation may have diameters of 100 nm or below and usual nanoparticles have a particle size of approximately 50 nm, which may cause blockage by two or more particles being pulled towards the pore throat. This effect is increased when both, surfactant and nanoparticles are contained in the injected fluid, where EK application leads to an agglomeration of the two additives, which clogs the pores of the formation.

3. Brief description of the invention

The above mentioned disadvantages of the prior art EK EOR techniques are overcome by a method according to claim 1.

Preferably, the above mentioned disadvantages are overcome by a method for enhancing oil recovery from an oil bearing earth formation, wherein the method comprises the following steps:

a. selecting an oil-bearing earth formation;

b. providing at least two wells, at least one production well and at least one

injection well to the oil-bearing earth formation;

c. providing at least two electrodes, at least one anode and at least one

cathode, to the oil-bearing earth formation, wherein the at least one cathode is positioned in or adjacent to the at least one production well;

d. injecting through the at least one injection well a fluid into the oil-bearing earth formation, wherein the fluid comprises at least one substance selected from the group consisting of: nanoparticles and surfactants; e. applying an electric current between the at least one anode and the at least one cathode in the oil-bearing earth formation, wherein the electric current is a direct current;

f. adjusting an onset current density to 0.05 - 15 A/m ² , preferably of 0.075 - 10 A/m ² , more preferably of 0.1 - 5, A/m ² , most preferably of 0.125 - 3 A/m ² , wherein m ² is defined as the height of the oil-bearing earth formation times V2 of the circumference of a cylinder having its center at the at least one cathode and the radius R being defined as the shortest distance between the at least one cathode and the at least one anode;

g. subsequently to step f., increasing the current density by at least 5%, preferably at least 10%, more preferably at least 20% and most preferably at least 30% of the onset current density to reach a maximum current density.

h. subsequent to step g., decreasing the maximum current density to the onset current density.

To overcome the disadvantages of the EK EOR techniques described in the art, a particular application of EK is proposed. It is in particular characterized by setting a specific current density, the so-called onset current density, and an oscillation of the current density between said set onset current density and a higher, so-called maximum current density.

The described method results in a reduction of the IFT, an altered wettability, an enlarged displacement efficiency, and an increased depth of penetration into both water-wet and in particular also oil-wet oil-bearing earth formations / reservoirs. Moreover, it provides for an improved economic and environmental application, as, on the one hand, energy consumption for the electrokinetics are reduced and, one the other hand, the amount and concentration of nanoparticles and surfactant can be reduced as compared to prior art methods.

The inventors have found out that with the method according the invention the degradation of the substances contained in the injected fluid decreases and the clogging of the pores in the rock formation is minimized. Additionally, the overall amount of required applied current is reduced which saves energy and related costs. Using the method according to claim 1 of the present invention, the recovery factor, which indicates the percentage of oil that can be depleted from an oil-bearing earth formation, is increased by 10% from the previously described maximal 87% to now 97%.

The methods works in and for all types of oil-bearing rock formations or reservoirs, particularly good results are obtained for oil-bearing earth formations made from or comprising sandstone, chalk or carbonate earth formations. Preferably, the steps g. and h. are repeated.

The repetition of steps g. and h. increases the recovery yield of the residual oil from the oil-bearing earth formation while decreasing the overall energy consumption. Preferably, the electric current between the at least one anode and the at least one cathode in the oil-bearing earth formation is selected such a voltage gradient of 0.05 - 2 V/cm, preferably of 0.06 - 1 V/cm, more preferably of 0.075 - 0-5 V/cm results.

The inventors discovered that the indicated voltage gradient is ideal in order to optimize recovery of the residual oil from the oil-bearing formation. Higher and lower voltage gradients may also work but come at the expense of a reduced efficacy and/or high energy consumption, which renders the described method economically less attractive. Preferably, the distance between the at least one anode and the at least one cathode in the oil-bearing earth formation is 1 - 5,000 meter, preferably 10 - 3,000 meter, more preferably 20 - 2,500 meter, most preferably 30 - 1,500 meter.

The described method was found to work in particular well at the indicated distances. Shorter distances (in the centimeter range) would of course also work, but are economically less attractive, while for distances larger than 5,000 meter, the method becomes less effective and requires very high voltages. Preferably, the onset current density applied subsequently to the injection of the fluid into the oil-bearing earth formation is applied for a duration of 1 - 60 days, preferably of 2 - 40 days, more preferably of 5 - 30 days. The inventors found out that application of the current density for the indicate duration results in a good economic trade-off between the amount of time spent for the recovery and the actual oil recovery rates.

Preferably, adjusting the current density is achieved by ramping the current density up or down by no more than 2.0 A/ m ² per unit time, preferably no more than 1.0 A/ m ² per unit time, more preferably no more than 0.5 A/m ² per unit time, wherein unit time is a period of 6 - 12 months, preferably 3 - 6 months and more preferably from 1 - 30 days. The inventors discovered that ramping the current density further reduces the consumption of energy and enhances the applicability of the process.

Preferably, the fluid is injected into the oil-bearing earth formation for a duration of 1 day - 2 years, preferably of 2 days - 1 year, more preferably of 3 - 200 days, most preferably of 5 - 50 days.

The indicated duration, dependent on the oil-bearing formation and the distance between injection and recovery well(s), have shown to be a good trade-off between the amount of time spent for the flooding and the associated economic and ecological costs on the one hand and the actual oil recovery rates on the other hand.

Preferably, the method comprises injecting subsequently at least two fluids with distinct composition subsequently, the injection of each fluid being followed or accompanied by the application of an onset current density.

Each fluid with its specific composition has its particular advantages. Surfactants achieve other technical effects than nanoparticles and also within the two categories, different surfactants and nanoparticles each have particular characteristics and effect the oil and/or the oil-bearing earth formation in a different way. Combining the individual advantages of two or fluids by subsequent injections leads to an optimization of the recovery process according to the method of the invention.

Preferably, multitude of anodes is provided around the at least one cathode positioned in or adjacent to the at least one production well, preferably the multitude of anodes is positioned on an about circular path with the at least one cathode being located at the center of said about circular path.

In a set-up according to this preferred embodiment, oil is recovered simultaneously from multiple directions and from a volume surrounding the at least one production well. This approach is particularly time effective and optimizes oil recovery rates from the treated oil-bearing earth formation.

Preferably, the nanoparticles have a diameter of ι - 700 nm, preferably of 2 - 400 nm, more preferably of 4 - 200 nm, most preferably of 5 - 100 nm, and comprise an electrically conductive material, preferably a metal or metal oxide such as iron, nickel, copper, iron oxide, nickel oxide, copper oxide or any combination of these.

Nanoparticles at the indicated size that comprise an electrically conductive material allow for a sufficient contact with the previously inaccessible so-called micro and nano pore throats within the oil-bearing earth formation, while being sufficiently small to pass the pores or pore throats under the conditions according to the invention in order not to clog them. Also, these particles create a strong abrasive force within the pore throats, freeing up fines from the oil-bearing earth formation fabric and targeting the upswept oil that is still present in said formation. Moreover, such particles have a sufficiently long contact time with the pores allowing for a good recovery of the residual oil.

Preferably, the surfactants are non-ionic or of cationic charge.

The main objectives of surfactant flooding are to alter the wettability of the earth formation and to reduce the IFT. Micro-emulsion is induced increasing the ability of mobilizing oil in water in order to assist in releasing of trapped, residual oil. At the same time it is tried to reduce the adsorption of the surfactant into the earth formation and to reduce the overall concentration of surfactant. Preferred surfactants that showed to provide very good properties in all these respects are cationic surfactants, such as in particular dodecyltrimethylammonium bromide (DTAB) and

cocoalkyltrimethylammonium chloride (CAC) as well as non-ionic surfactants, such as in particular ethoxylated alcohols, poly-oxyethylene alcohol (POA) and alkyl polyglycoside (APG).

Preferably, the nanoparticles and/or surfactants are each contained in the fluid to be injected into the oil-bearing earth formation at a concentration of less than 7,000 ppm, preferably less than 5,000 ppm, more preferably less than 3,000 ppm.

The inventors found out that the use of nanoparticles in the indicated concentrations yields good oil recovery rates while reducing the amount of nanoparticles required to a minimum in order to reduce potential adverse environmental effects and to reduce the costs.

Preferably, the fluid to be injected into the oil-bearing earth formation comprises at least one kind of nanoparticles and at least one surfactant. The inventors discovered that the advantageous effects of the method and here in particular the anti-clogging effect actually allow for the simultaneous use of both, nanoparticles and surfactant(s), which according to previously available methods would not have been possible due to the clogging of the pores in the oil-bearing formation. With the described method, the respective advantageous effects of nanoparticles and surfactant(s) can now be combined, saving time for the recovery as well as energy, as the electrokinetics are applied for both, the nanoparticle and the surfactant floodings at the same time rather that individually for each flooding.

Preferably, the fluid to be injected into the oil-bearing earth formation comprises also at least one complexing agent, preferably an amine or EDTA.

Complexing and chelating agents such as in particular amines, organic acids and EDTA assist in complexing and binding divalent cations released during the flooding of the oil-bearing formation, thus preventing them from binding again, such as to the pore walls. Accordingly, the risk of clogging is further reduced by ensuring a balanced and more uniform dispersed distribution.

Further preferred embodiments of the present invention relate to the dependent claims.

4. Brief description of the drawings

In the following preferred embodiments of the invention are described by reference to the drawings in which shows:

Fig. 1 a side sectional view of an oil recovery site;

Fig. 2 a side sectional view of an oil recovery site illustrating an area for the

determination of an onset current density;

Fig. 3 a top view of an oil recovery site for performing a preferred embodiment of the invention;

Fig. 4 a three-dimensional sectional view of an oil recovery site for performing a preferred embodiment of the invention; and

Fig. 5 a diagram illustrating a preferred embodiment of the invention.

5. Preferred embodiments

In the following preferred embodiments of the invention are described in detail with respect to the accompanying figures.

Fig. 1 shows a simplified oil recovery site 100 in which the method according the invention can be used. A production well 1 extents through different non-oil-bearing earth formations 32, 34, 36 up to an oil-bearing earth formation 30. Enhanced oil recovery (EOR) techniques are used to recover residual oil remaining in the oil-bearing earth formation 30. To this end a fluid 20, preferably water with special additives are pumped into the injection well 2 such that it also reaches the oil-bearing earth formation 30. Thus, the fluid 20 is injected under pressure into the oil-bearing earth formation 30 in order to push the residual oil in the oil-bearing earth formation 30 towards the production well 1, from where the oil 10 is pumped via the production well 1. Simultaneously the residual oil in the oil-bearing earth formation 30 is recovered by the fluid. The fluid 20 comprises for example water-soluble polymers, surfactants, nanoparticles, and acids and mixtures thereof as additives. In addition electrokinetics (EK) can be used to assist oil recovery from the oil-bearing earth formation. To this end, an electric field 5 is established between an anode 3 at the injection well 2 and a cathode 4 at the production well 1. The strength of the electrical field 5 can be described by its current density J which can be expressed in ampere per square meter (A/m ² ). The area 50 on which the strength of the current density is base can be calculated by the height of the oil-bearing earth formation 30 times V2 of the circumference of a cylinder having its center at the at least one cathode 4 and the radius R being defined as the shortest distance between the at least one cathode 4 and the at least one anode 3 as it is shown in Fig. 2. Fig. 3 shows an exemplary top-view arrangement of production well 1 and cathode 4, several injection wells 2a, 2b as well as several anodes 3a, 3b, 3c, 3d. Production well 1 and cathode are located at the center, surrounded by 20 anodes 3 which are themselves surrounded by 10 injection wells 2. Fig. 4 shows how in an arrangement of wells 1, 2 and electrodes 3, 4 as shown in Fig. 3, several modes of EOR oil recovery can be envisaged: 4 oil-bearing earth formations 30 are separated from one and another by earth formations that do not bear oil. At the production well 1, four electrodes 4a, 4b, 4c, 4d are positioned at each of the oil-bearing earth formations 30. For the oil-bearing earth formation 30 at the surface, only EK is applied via an accordingly positioned anode 3a, but no injection well targets this layer.

Similarly, the bottom oil-bearing earth formation 30 only an anode 3d is positioned for EK flooding. The two oil-bearing earth formations 30 in the center are equipped with both anodes 3b, 3c and injection wells 2a, 2b allowing for EK assisted EOR flooding according to the invention. Oil flow 40 is indicated towards production well 1 and cathode 4c.

Fig. 5 shows a diagram depicting the timing of a preferred sequence of fluids 20, 60, 62, 64 to be injected into the oil-bearing earth formation 30 referred to as "recipe #1". The different floodings with NiO 60, alkyl polyglucoside (APG) 62 and CuO 64 are overlaid with the specific EK flooding according to the invention.

Recipe #1 is characterized by the following sequence of fluids that are each water-based and comprise these additives: NiO 60 followed by APG 62, followed by NiO 60, followed by APG 62, followed by NiO 60, followed CuO 64.

The current density (J) 70 is ramped up 78 and down 79 in a certain current density window 80, 82, defined by a maximum current density (Jiwax) 74, 76 and the so-called onset current density (Jonset) 75- The current density J 70 may be reduced below the onset current density 75 when initiating the injection of the next flooding, as can be seen in the diagram, at 72 during the initiation of the surfactant flooding with APG. The max onset current density Juax 74, 76 may vary dependent on the composition of the fluid injected during the flooding. In the example, the maximum current density JMaxa 76 is lower for NiO nano flooding than the maximum current density JMaxi 74 for the APG flooding. Likewise, the onset current density 75 may vary dependent on the composition of the fluid 20 injected during the flooding. In shown recipe #1, the onset current density Jonset 75 is equal for all three different fluids 60, 62, 64 that are injected. During each flooding phase, the current density 70 has to oscillate at least once between onset current density 75 and maximum current density 74, 76. The current density 70 may, however, oscillate more than once, as is shown in the example for the APG surfactant flooding.

The current density J 70 can be ramped up 78 or down 79 by no more than 2.0 A/m ² per unit time, preferably no more than 1.0 A/m ² per unit time, preferably, no more than 0.5 A/m ² per unit time. The unit time is a period of 6 - 12 months, preferably 3 - 6 month and more preferably from 1 - 30 days. Preferably, the fluid 20 is injected into the oil-bearing earth formation 30 for a duration of 1 day - 2 years, preferably of 2 days - 1 year, more preferably of 3 - 200 days, most preferably of 5 - 50 days.

The table below indicates the timing for recipe #1 as illustrated in Figure 5 from t ₀ to for usual oil-bearing carbonate rock formations and for a spatial distance between anode / injection well and cathode / production well of 100 meters.

Q signifies the reservoir average flow rate during injection of the fluid. In tight carbonate reservoirs said flow rate may be as low as 0.25 ft/day, while for permeable carbonate reservoirs the flow rate may reach 2+ ft/day. PV signifies pore volume measured in ft ³ , i.e. the total volume of the pores in the oil-bearing earth formation / reservoir. Fractional PV signifies the pore volume in the reservoir that is actually penetrated during flooding measured also in ft ³ .

The example illustrates the timing for a reservoir with a total pore volume of 554.80 ft ³ , dependent on a varying fractional pore volume (from 0.05 to 0.75 ft ³ ) and a reservoir average flow rate of 2 ft/day. Depending on the fractional pore volume, conducting the flooding according to recipe #1 as a preferred embodiment of the present invention, takes accordingly from 13.87 days (fractional PV of 0.05 ft ³ ) to 208.05 days (fractional PV of 0.75 ft ³ ) from t ₀ to t ₆ .

Another preferred sequence of fluids to be injected into the oil-bearing earth formation is recipe #2, which is characterized by the following sequence of fluids that are each water-based and comprise these additives: NiO followed APG, followed by CuO, followed by APG.

An additional preferred sequence of fluids to be injected into the oil-bearing earth formation is recipe #3, which is characterized by the following sequence of fluids that are each water-based and comprise these additives: NiO followed by APG, followed by NiO, followed by APG, followed by CuO.

Preferred surfactants are compatible with HPHTHS (High Pressure High Temperature and High Salinity). Non-ionic surfactants are preferred as they do not have a negative effect, when changing the reservoir rock charge during EK EOR. A variety of surfactants can be used based on the target reservoir formation and its respective constituents. The surfactant concentration is dependent on achieving both CMC (critical micelles concentration) to ensure micro-emulsion as well as economic feasibility. Usually concentrations of no more than 5,000 ppm are preferred. The most preferred surfactant is alkyl polyglucoside (APG).

Preferred nanoparticles are those that can be driven by an electric field through electrophoresis and electroosmosis. Thus the nanoparticles comprise an electrically conductive material. Preferred nanoparticles have a diameter of between 1 and 700 nm, preferably of 2 - 400 nm, preferably of 4 - 200 nm, preferably of 5 - 100 nm, and preferably below 100 nm and can be of spherical, layered or tubular shape or combinations of these three. The nanoparticle concentration is dependent on achieving both suspensions, while ensuring uniform distribution and avoiding sedimentation as well as economic feasibility. Usually concentrations of no more than 5,000 ppm are preferred. Particular preferred nanoparticles or combinations of nanoparticles comprise: iron, nickel, copper, iron and nickel, ion and copper, nickel and copper, iron and nickel and copper, iron oxide, nickel oxide, copper oxide, iron oxide and nickel oxide, iron oxide and copper oxide, nickel oxide and copper oxide, iron oxide and nickel oxide and copper oxide.

In a preferred embodiment, several fluids are subsequently injected, wherein each injection is either followed or accompanied by the varying current density according to the invention. Between each injection of a fluid, there may be a "pause", i.e. a certain period of time during which either no fluid is injected while continuing the EK flooding according to the invention, or vice versa, the next fluid is injected and the EK flooding according to the invention is only resumed later, or both, fluid injection and EK flooding according to the invention are interrupted.