Method for carrying out water flooding by utilizing injection solution containing dihydric phosphate

Abstract

Methods are provided for increasing hydrocarbon production from a subterranean formation by water flooding with an injected solution containing dihydrogen phosphate ions.

Description

[0001] Priority claim

[0002] This application claims priority to U.S. patent application No. 17 / 956,569, filed on September 29, 2022, the entire contents of which are incorporated herein by reference. Technical Field

[0003] The present disclosure describes a method for utilizing a method containing dihydrogen phosphate ions (H2PO4 - ) is injected into the solution for water flooding. The concentration of dihydrogen phosphate ions in the injection solution can be gradually reduced. Background Art

[0004] The practice of efficient and effective oil recovery from underground formations requires a detailed understanding of the physicochemical processes associated with the oil recovery process. Water injection is a widely used method for improving hydrocarbon recovery. The injected water or brine is typically underground aquifer water, surface water and / or seawater, depending on the location of the underground formation and the source of the water. Injection water salinity plays an important role in controlling oil recovery from carbonate formations due to its strong effect on wettability. Specifically, some individual ions dissolved in brine have been shown to have a favorable effect on wettability, while other ions have not been shown to have any effect on reservoir wettability. Therefore, there is a need for methods for providing favorable wettability changes and enhancing oil recovery in carbonates. Summary of the invention

[0005] The present disclosure provides a method for waterflooding. In some embodiments, the method for waterflooding includes introducing a first injection solution containing about 400 ppm to about 1000 ppm of dihydrogen phosphate ions into an underground formation; and introducing a second injection solution containing dihydrogen phosphate ions into the underground formation, wherein the concentration of dihydrogen phosphate ions of the second injection solution is about 200 ppm to about 800 ppm, and its concentration of dihydrogen phosphate ions is at least about 200 ppm lower than that of the first injection solution, and wherein at least a portion of hydrocarbons present in the underground formation are displaced.

[0006] In some embodiments, the pH of the first injection solution is from about 5.0 to about 5.5.

[0007] In some embodiments, the pH of the second injection solution is from about 5.0 to about 5.5.

[0008] In some embodiments, the first injection solution comprises seawater.

[0009] In some embodiments, the second injection solution comprises seawater.

[0010] In some embodiments, the amount of first injection solution introduced into the subterranean formation is from about 0.3 to about 0.5 pore volumes.

[0011] In some embodiments, the amount of second injection solution introduced into the subterranean formation is from about 0.3 to about 0.5 pore volumes.

[0012] In some embodiments, the first injection solution includes about 1000 ppm of dihydrogen phosphate ions.

[0013] In some embodiments, the first injection solution comprises seawater.

[0014] In some embodiments, the second injection solution comprises seawater.

[0015] In some embodiments, the method of waterflooding further comprises introducing a chase solution (which comprises aquifer water, surface water, seawater, or a combination thereof) into the subterranean formation.

[0016] In some embodiments, the amount of squeeze solution introduced into the subterranean formation is from about 0.5 to about 1.0 pore volumes.

[0017] In some embodiments, the subterranean formation comprises a carbonate formation.

[0018] In some embodiments, the first injection solution is introduced after primary production of hydrocarbons from the subterranean formation.

[0019] In some embodiments, the method of waterflooding further comprises producing hydrocarbons from the underground formation.

[0020] The present disclosure also provides a method for water flooding, which includes introducing a first injection solution containing about 1000 ppm of dihydrogen phosphate ions into an underground formation; introducing a second injection solution containing about 800 ppm of dihydrogen phosphate ions into the underground formation; introducing a third injection solution containing about 600 ppm of dihydrogen phosphate ions into the underground formation; introducing a fourth injection solution containing about 400 ppm of dihydrogen phosphate ions into the underground formation; and introducing a fifth injection solution containing about 200 ppm of dihydrogen phosphate ions into the underground formation, wherein at least one of the first injection solution, the second injection solution, the third injection solution, the fourth injection solution and the fifth injection solution displaces at least a portion of the hydrocarbons present in the underground formation.

[0021] In some embodiments, the pH of the first infusion solution, the second infusion solution, the third infusion solution, the fourth infusion solution, and / or the fifth infusion solution is from about 5.0 to about 5.5.

[0022] In some embodiments, the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and / or the fifth injection solution comprises seawater.

[0023] In some embodiments, the amount of the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and / or the fifth injection solution introduced into the subterranean formation is from about 0.3 to about 0.5 pore volumes.

[0024] In some embodiments, the method of waterflooding further comprises injecting a squeeze solution (including aquifer water, surface water, seawater, or a combination thereof) into the underground formation.

[0025] In some embodiments, the amount of squeeze solution introduced into the subterranean formation is from about 0.5 to about 1.0 pore volumes.

[0026] In some embodiments, the subterranean formation comprises a carbonate formation.

[0027] In some embodiments, the first injection solution is introduced after primary production of hydrocarbons from the subterranean formation.

[0028] In some embodiments, the method of waterflooding further comprises producing hydrocarbons from the underground formation. BRIEF DESCRIPTION OF THE DRAWINGS

[0029] Figure 1 The various ions squeezed into the thin film water layer between the calcite surface and the crude oil are shown.

[0030] Figure 2 The zeta potential values ​​of different brine solutions at the calcite / brine interface are shown.

[0031] Figure 3 Zeta potential values ​​of different brine solutions at the crude oil / brine interface are shown.

[0032] Figure 4A and 4B The contact angles of different saline solutions are shown. Figure 4A Seawater without salt additives is shown, and Figure 4B Shown is seawater with 1000 ppm of sodium dihydrogen phosphate.

[0033] Figure 5 Experimental and modeled zeta potential values ​​for different brine solutions at the calcite / brine interface are shown. DETAILED DESCRIPTION

[0034] Reference will now be made in detail to certain embodiments of the disclosed subject matter.While the disclosed subject matter will be described in conjunction with the enumerated claims, it will be understood that the illustrated subject matter is not intended to limit the claims to the disclosed subject matter.

[0035] Water injection can be used to improve hydrocarbon recovery from underground formations by increasing pressure in underground formations and displacing hydrocarbons. Water injection can be performed after primary recovery of underground formations. Underground aquifers, surface water and / or seawater can be used as injection water (depending on the location). Typically, for pH between 5 and 8, the ζ-potential of brine / crude oil is negative due to carboxylate groups in the crude oil surface, while the ζ-potential of brine / carbonate is positive due to dissolved magnesium and calcium ions in the brine solution (which interact and adsorb on the calcite surface). The salinity of the injected water can change the surface charge and the corresponding ζ-potential, thereby affecting hydrocarbon recovery from carbonate formations due to the effect on wettability. However, the concentration of some ions can affect wettability, while other ions do not affect wettability. Adding certain anions (such as iodide ions, sulfate and / or borate) to the brine solution can change the brine / carbonate ζ-potential to become negative, thereby generating repulsion between the brine / carbonate and brine / crude oil interfaces. This electrostatic repulsion changes the wettability to be more water-wet and thereby results in additional hydrocarbon recovery.

[0036] The present disclosure provides compositions and methods for waterflooding during hydrocarbon recovery from underground formations. The compositions contain a dilute concentration of sodium dihydrogen phosphate (NaH2PO4) in the injected water, such as 200-1000 ppm. Without wishing to be bound by any particular theory, it is believed that the dihydrogen phosphate ion (H2PO4 - ) interact with the calcite / brine and oil / brine interfaces to change the surface charge to negative or more negative and improve the wettability in the carbonates toward a water-wet state, thereby increasing hydrocarbon production.

[0037] In addition, H2PO4 - The ions can also lower the pH of the injected water to a slightly acidic pH range, such as 5.0-5.5. Without wishing to be bound by any particular theory, it is believed that the slightly acidic pH can eliminate blockage of pore throats and cause mineral dissolution to increase permeability and improve pore connectivity without causing corrosion of components of the hydrocarbon production well.

[0038] The proposed water composition can thus be used as an improved oil recovery (IOR) agent in water flooding applications to increase hydrocarbon recovery relative to other water flooding methods. The method comprises introducing 0.3 to 0.5 pore volumes of H2PO4 - The injection solution of ions is used as the main oil recovery slug, followed by the introduction of up to 1.0 pore volume of conventional injection water as the chase water. The main recovery slug can also be gradually reduced by successively reducing the concentration of dihydrogen phosphate ions. In some embodiments, the concentration of dihydrogen phosphate ions is successively reduced from 1,000 ppm to 200 ppm using a concentration step size of 200 ppm.

[0039] definition

[0040] Unless otherwise defined, all technical and scientific terms used in this document have the same meaning as commonly understood by those of ordinary skill in the art to which this application belongs. Methods and materials used in this application are described in this document; other suitable methods and materials known in the art may also be used. The materials, methods and examples are illustrative only and are not intended to be limiting. All publications, patent applications, patents, sequences, database entries and other references mentioned in this document are incorporated by reference in their entirety. In the event of a conflict, the present specification (including definitions) shall prevail.

[0041] Values ​​expressed in range format should be interpreted in a flexible manner to include not only the values ​​explicitly listed as range limits, but also all individual values ​​or subranges covered within the range, as if each value and subrange were explicitly listed. For example, a range of "about 0.1% to about 5%" or "about 0.1% to 5%" should be interpreted to include not only about 0.1% to about 5%, but also individual values ​​(e.g., 1%, 2%, 3%, and 4%) and subranges (e.g., 0.1% to 0.5%, 1.1% to 2.2%, and 3.3% to 4.4%) within the indicated range. Unless otherwise specified, the expression "about X to Y" has the same meaning as "about X to about Y". Similarly, unless otherwise specified, the expression "about X, Y, or about Z" has the same meaning as "about X, about Y, or about Z".

[0042] As used in this disclosure, the term "about" can allow a certain degree of variation in a value or range, for example, within 10%, within 5%, or within 1% of a stated value or a stated range limit.

[0043] As used in this disclosure, the terms "a", "an", and "the" are used to include one or more, unless the context clearly dictates otherwise. The term "or" is used to refer to a non-exclusive "or", unless otherwise specified. The statement "at least one of A and B" has the same meaning as "A, B, or A and B". In addition, it should be understood that the words or terms used in this disclosure and not otherwise defined are for descriptive purposes only and not for limiting purposes. The use of any section headings is intended to aid in reading the document and should not be construed as limiting; information related to the section heading may appear within or outside that particular section.

[0044] In the methods described in this disclosure, the actions may be performed in any order except when a time or order of operations is explicitly stated. In addition, specified actions may be performed simultaneously unless explicit claim language states that they are performed separately. For example, a required action of performing X and a required action of performing Y may be performed simultaneously in a single operation, and the resulting process will fall within the literal scope of the required process.

[0045] As used in the present disclosure, the term "subsurface formation" may refer to any material below the surface of the earth (including below the seafloor surface). For example, the subsurface formation or material may be any part of a wellbore and any part of an underground oil-producing or water-producing formation or region in contact with a wellbore fluid. Placing a material into a subsurface formation may include contacting the material with any part of the wellbore or with any underground region in contact with the wellbore fluid. Subsurface materials may include any material placed in a wellbore, such as cement, drill pipe, liner, tubing, casing, or filter tube; placing a material in a subsurface formation may include contacting such subsurface materials. In some examples, a subsurface formation or material may be any underground region capable of producing liquid or gaseous petroleum materials, water, or any underground portion in contact with liquid or gaseous petroleum materials or water fluids. In some embodiments, the subsurface formation is an oil well.

[0046] As used in this disclosure, the term "water flooding" refers to a secondary recovery method in which water is injected into an underground formation to displace residual hydrocarbons (such as oil) and increase the production of hydrocarbons from the underground formation. The water from the injection well physically sweeps the displaced hydrocarbons (such as oil) to adjacent production wells.

[0047] Method for enhancing hydrocarbon recovery from a subterranean formation

[0048] The present disclosure provides a method for enhancing hydrocarbon recovery from an underground formation using water flooding after primary production of the underground formation. The method includes water flooding with an injection solution containing dihydrogen phosphate ions. In some embodiments, the underground formation is porous. In some embodiments, the underground formation includes a carbonate formation, such as calcite.

[0049] Therefore, the present disclosure provides a method for water flooding, which includes introducing a first injection solution containing about 400 ppm to about 1000 ppm of dihydrogen phosphate ions into an underground formation, and introducing a second injection solution containing dihydrogen phosphate ions into the underground formation, wherein the concentration of dihydrogen phosphate ions in the second injection solution is about 200 ppm to about 800 ppm, and its concentration of dihydrogen phosphate ions is at least about 200 ppm lower than that of the first injection solution, and wherein at least one of the first injection solution and / or the second injection solution displaces at least a portion of the hydrocarbons present in the underground formation.

[0050] Injection solution for water flooding containing dihydrogen phosphate ions

[0051] Typically, a first injection solution is introduced into the subterranean formation. In some embodiments, the concentration of dihydrogen phosphate ions in the first injection solution is from about 200 ppm to about 1000 ppm, such as from about 200 ppm to about 300 ppm, from about 200 ppm to about 400 ppm, from about 200 ppm to about 500 ppm, from about 200 ppm to about 600 ppm, from about 200 ppm to about 700 ppm, from about 200 ppm to about 800 ppm, from about 200 ppm to about 900 ppm, from about 300 ppm to about 400 ppm, from about 300 ppm to about 500 ppm, from about 300 ppm to about 600 ppm, from about 300 ppm to about 700 ppm, from about 200 ppm to about 800 ppm, from about 200 ppm to about 900 ppm, ppm to about 700 ppm, about 400 ppm to about 800 ppm, about 400 ppm to about 900 ppm, about 400 ppm to about 1000 ppm, about 500 ppm to about 600 ppm, about 500 ppm to about 700 ppm, about 500 ppm to about 800 ppm, about 500 ppm to about 900 ppm, about 500 ppm to about 1000 ppm, about 600 ppm to about 700 ppm, about 600 ppm to about 800 ppm, about 600 ppm to about 900 ppm, about 600 ppm to about 1000 ppm, about 700 ppm to about 800 ppm, about 700 ppm to about 900 ppm, about 700 ppm to about 1000 ppm, about 800 ppm to about 900 ppm, about 800 ppm to about 1000 ppm, about 900 ppm to about 1000 In some embodiments, the concentration of the dihydrogen phosphate ions in the first injection solution is about 1000 ppm. Without wishing to be bound by any particular theory, it is believed that the concentration of the dihydrogen phosphate ions exceeding about 1000 ppm may cause the injection solution to be acidic and corrosive. It is also believed that the concentration of the dihydrogen phosphate ions exceeding about 1000 ppm may increase costs. On the other hand, it is believed that the concentration of the dihydrogen phosphate ions less than about 200 ppm may not affect the reservoir wettability.

[0052] In some embodiments, after the first injection solution is introduced, a second injection solution is introduced into the underground formation. In some embodiments, the second injection solution has a concentration of dihydrogen phosphate ions of about 200 ppm to about 800 ppm, and has a concentration of dihydrogen phosphate ions that is at least about 200 ppm lower than the first injection solution. In some embodiments, the concentration of dihydrogen phosphate ions in the second injection solution is from about 200 ppm to about 800 ppm, such as from about 200 ppm to about 300 ppm, from about 200 ppm to about 400 ppm, from about 200 ppm to about 500 ppm, from about 200 ppm to about 600 ppm, from about 200 ppm to about 700 ppm, from about 300 ppm to about 400 ppm, from about 300 ppm to about 500 ppm, from about 300 ppm to about 600 ppm, from about 300 ppm to about 700 ppm, from about 300 ppm to about 800 ppm, from about 400 ppm to about 500 ppm, from about 400 ppm to about 600 ppm, from about 400 ppm to about 700 ppm, from about 400 ppm to about 800 ppm, from about 500 ppm to about 600 ppm, from about 500 ppm to about 700 ppm, or from about 500 ppm to about 800 ppm. In some embodiments, the concentration of dihydrogen phosphate ions in the second injection solution is about 800 ppm. In some embodiments, the concentration of dihydrogen phosphate ions in the second injection solution is about 600 ppm. In some embodiments, the concentration of dihydrogen phosphate ions in the second injection solution is about 500 ppm. In some embodiments, the concentration of dihydrogen phosphate ions in the second injection solution is about 400 ppm. In some embodiments, the concentration of dihydrogen phosphate ions in the second injection solution is about 200 ppm.

[0053] In some embodiments, a first injection solution containing dihydrogen phosphate ions is introduced into a subterranean formation, and additional injection solutions are introduced such that the concentration of dihydrogen phosphate ions is sequentially reduced from about 1000 ppm to about 200 ppm, such as from about 300 ppm to about 200 ppm, about 400 ppm to about 200 ppm, about 500 ppm to about 200 ppm, about 600 ppm to about 200 ppm, about 700 ppm to about 200 ppm, about 800 ppm to about 200 ppm, about 900 ppm to about 200 ppm, about 400 ppm to about 300 ppm, about 500 ppm to about 300 ppm, about 600 ppm to about 300 ppm, about 700 ppm to about 300 ppm, about 800 ppm to about 300 ppm, about 900 ppm to about 200 ppm, about 1000 ppm to about 300 ppm, about 500 ppm to about 400 ppm ppm, about 600 ppm to about 400 ppm, about 700 ppm to about 400 ppm, about 800 ppm to about 400 ppm, about 900 ppm to about 400 ppm, about 1000 ppm to about 400 ppm, about 600 ppm to about 500 ppm, about 700 ppm to about 500 ppm, about 800 ppm to about 500 ppm, about 900 ppm to about 500 ppm, about 1000 ppm to about 500 ppm, about 700 ppm to about 600 ppm, about 800 ppm to about 600 ppm, about 900 ppm to about 600 ppm, about 1000 ppm to about 600 ppm, about 800 ppm to about 700 ppm, about 900 ppm to about 700 ppm, about 1000 ppm to about 700 ppm, about 900 ppm to about 800 ppm, about 1000 ppm to about 700 ppm In some embodiments, a first injection solution containing dihydrogen phosphate ions is introduced into a subterranean formation, and additional injection solutions are introduced such that the concentration of dihydrogen phosphate ions is successively reduced from about 1000 ppm to about 200 ppm.

[0054] In some embodiments, the concentration step size of the dihydrogen phosphate ion between successive injection solutions is reduced by about 100 ppm, about 200 ppm, about 300 ppm, about 400 ppm, about 500 ppm, about 600 ppm, about 700 ppm or about 800 ppm. In some embodiments, the concentration step size of the dihydrogen phosphate ion between successive injection solutions is reduced by about 200 ppm. Without wishing to be bound by any particular theory, it is believed that the wettability change process can be maximized by gradually reducing the concentration by successively reducing the dihydrogen phosphate ion with a step size of about 200 ppm, and doing so will not generate excessive costs. Relative to a step size of about 200 ppm, using a smaller step size (such as about 100 ppm) will increase operating costs without any significant benefits. Relative to a step size of about 200 ppm, using a larger step size (such as about 500 ppm) may cause reduced hydrocarbon recovery.

[0055] In some embodiments, two, three, four, or five injection solutions containing dihydrogen phosphate ions are sequentially introduced into the subterranean formation, wherein each subsequent injection solution has a lower concentration than the previous injection solution.

[0056] In some embodiments, a first injection solution containing about 1000 ppm of dihydrogen phosphate ions, a second injection solution containing about 800 ppm of dihydrogen phosphate ions, a third injection solution containing about 600 ppm of dihydrogen phosphate ions, a fourth injection solution containing about 400 ppm of dihydrogen phosphate ions, and a fifth injection solution containing about 200 ppm of dihydrogen phosphate ions are sequentially introduced into the underground formation.

[0057] Examples of water sources for injection solutions (such as the first, second, third, fourth, and fifth injection solutions) include aquifer water, surface water, and seawater. In some embodiments, the water source for injection solution is seawater. In some embodiments, salts containing dihydrogen phosphate ions such as sodium dihydrogen phosphate (NaH2PO4) and / or potassium dihydrogen phosphate (KH2PO4) are added to the water source to obtain the injection solution. In some embodiments, salts containing dihydrogen phosphate ions are added to existing water injection pipelines such as seawater injection pipelines before the wellhead of the injection well.

[0058] In some embodiments, the amount of injection solution (such as the first, second, third, fourth and fifth injection solutions) is about 0.3 to about 0.5 pore volumes, such as about 0.3 to about 0.4 pore volumes, about 0.4 to 0.5 pore volumes, about 0.3 pore volumes, about 0.4 pore volumes, about 0.5 pore volumes. In some embodiments, the amount of injection solution is about 0.3 to about 0.5 pore volumes.

[0059] In some embodiments, the pH of the injection solution (e.g., the first, second, third, fourth, and fifth injection solutions) is about 5.0 to about 5.5, such as about 5.0 to about 5.1, about 5.0 to about 5.2, about 5.0 to about 5.3, about 5.0 to about 5.4, about 5.1 to about 5.2, about 5.1 to about 5.3, about 5.1 to about 5.4, about 5.1 to about 5.5, about 5.2 to about 5.3, about 5.2 to about 5.4, about 5.2 to about 5.5, about 5.3 to about 5.4, about 5.3 to about 5.5, about 5.4 to about 5.5, about 5.0, about 5.1, about 5.2, about 5.3, about 5.4, or about 5.5. In some embodiments, the pH of the injection solution is about 5.0 to about 5.5. Without wishing to be bound by theory, it is believed that the slightly acidic pH of the injection solution may eliminate pore throat blockage and cause some mineral dissolution, resulting in increased permeability and improved pore connectivity without causing corrosion of components of the hydrocarbon production well.

[0060] Surface charge and wettability

[0061] Figure 1 Depicted are different ions from brine in a thin film of water between the calcite and crude oil surfaces. Without wishing to be bound by any particular theory, it is believed that dissolved ions can adsorb on the crude oil, calcite, and brine surfaces, thereby creating an overall surface charge at each interface. The surface charge has a corresponding zeta potential electrokinetic parameter that can be measured experimentally.

[0062] Without wishing to be bound by any particular theory, it is believed that seawater contains high concentrations of divalent cations such as Mg +2 and Ca +2 , thereby causing the calcite surface to carry a positive surface charge. Adding dihydrogen phosphate ions to seawater can form a surface complex adsorbed on calcite, which changes the surface charge from a positive surface charge to a negative surface charge. Making the brine / carbonate ζ-potential more negative can produce repulsion between the brine / carbonate and brine / crude oil interfaces, changing the wettability to more water-wet, thereby increasing hydrocarbon recovery. Due to the carboxylate groups in the crude oil composition, the surface charge in crude oil is mainly negative. Therefore, relative to the crude oil / brine interface, it can be expected that brine containing dihydrogen phosphate ions has a greater impact on the surface charge of the calcite / brine interface (as measured by ζ-potential). An injection solution containing about 1000 ppm of dihydrogen phosphate ions in seawater can cause the ζ-potential of the brine / carbonate interface to change from positive to negative, while being safe and cost-effective to use in field operations.

[0063] Changes in wettability, such as those due to changes in surface charge, can be observed through contact angle measurements. A decrease in the contact angle would indicate that the system has transitioned to a more water-wet state, resulting in increased hydrocarbon production.

[0064] Squeeze water

[0065] In some embodiments, squeeze water is introduced into the underground formation after all of the injection solutions employed are introduced. In some embodiments, the amount of squeeze water introduced is from about 0.5 to about 1.0 pore volume, such as from about 0.5 to about 0.6 pore volume, from about 0.5 to about 0.7 pore volume, from about 0.5 to about 0.8 pore volume, from about 0.5 to about 0.9 pore volume, from about 0.6 to about 0.7 pore volume, from about 0.7 to about 0.8 pore volume, from about 0.7 to about 0.9 pore volume, from about 0.7 to about 1.0 pore volume, from about 0.8 to about 0.9 pore volume, from about 0.8 to about 1.0 pore volume, from about 0.9 to about 1.0 pore volume, from about 0.5 pore volume, from about 0.6 pore volume, from about 0.7 pore volume, from about 0.8 pore volume, from ...5 pore volume, from about 0.6 pore volume, from about 0.7 pore volume, from about 0.8 pore volume, from about 0.5 pore volume, from about 0.6 pore volume, from about 0.7 pore volume, from about 0.8 pore volume, from about 0.9 pore volume, from about 0.7 to about 1.0 pore volume, from about 0.9 to about 1.0 pore volume, from about 0.5 pore volume, from about 0.6 pore volume, from about 0.7 pore volume, from about 0.8 pore volume, In some embodiments, the amount of squeeze water introduced is about 1.0 pore volume. In some embodiments, the squeeze water comprises aquifer water, surface water, and / or seawater.

[0066] Method for water flooding using an injection solution containing dihydrogen phosphate ions

[0067] Thus, the present disclosure provides methods of waterflooding using the injection solutions described herein.In some embodiments, the methods of the present disclosure result in increased oil recovery, such as oil recovery from a carbonate formation.

[0068] The present disclosure provides a method for water flooding, wherein the method includes introducing a first injection solution containing about 400 ppm to about 1000 ppm of dihydrogen phosphate ions into an underground formation, and then introducing a second injection solution containing dihydrogen phosphate ions into the underground formation, wherein the concentration of dihydrogen phosphate ions of the second injection solution is about 200 ppm to about 800 ppm, and the concentration of dihydrogen phosphate ions thereof is at least about 200 ppm lower than that of the first injection solution, thereby displacing at least a portion of the hydrocarbons present in the underground formation. In some embodiments, the pH of the first solution and / or the second solution is about 5.0 to 5.5. In some embodiments, the first solution and / or the second solution includes seawater. In some embodiments, the amount of the first solution and / or the second solution introduced into the underground formation is about 0.3 to 0.5 pore volumes. In some embodiments, the first injection solution includes 1000 ppm of dihydrogen phosphate ions. In some embodiments, after the first and second injection solutions, a squeeze solution (comprising aquifer water, surface water, seawater or a combination thereof) is introduced into the underground formation. In some embodiments, the amount of the squeeze solution introduced into the underground formation is about 0.5 to about 1.0 pore volumes. In some embodiments, the underground formation comprises a carbonate formation. In some embodiments, the first injection solution is introduced after primary production of hydrocarbons from the underground formation. In some embodiments, the method for water flooding also comprises producing hydrocarbons from the underground formation.

[0069] The present disclosure also provides a method of water flooding, wherein the method includes introducing a first injection solution containing about 1000 ppm of dihydrogen phosphate ions into an underground formation; introducing a second injection solution containing about 800 ppm of dihydrogen phosphate ions into an underground formation; introducing a third injection solution containing about 600 ppm of dihydrogen phosphate ions into an underground formation; introducing a fourth injection solution containing about 400 ppm of dihydrogen phosphate ions into an underground formation; and introducing a fifth injection solution containing about 200 ppm of dihydrogen phosphate ions into an underground formation, wherein at least one of the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and the fifth injection solution displaces at least a portion of the hydrocarbons present in the underground formation. In some embodiments, the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and / or the fifth injection solution have a pH of about 5.0 to about 5.5. In some embodiments, the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and / or the fifth injection solution include seawater. In some embodiments, the amount of the first injection solution, the second injection solution, the third injection solution, the fourth injection solution and / or the fifth injection solution introduced into the underground formation is about 0.3 to about 0.5 pore volume. In some embodiments, after the first, second, third, fourth and fifth injection solutions, a squeeze solution (including aquifer water, surface water, seawater or a combination thereof) is introduced into the underground formation. In some embodiments, the amount of the squeeze solution introduced into the underground formation is about 0.5 to about 1.0 pore volume. In some embodiments, the underground formation includes a carbonate formation. In some embodiments, the first injection solution is introduced after a primary hydrocarbon recovery from the underground formation. In some embodiments, the method of water flooding also includes producing hydrocarbons from the underground formation.

[0070] Example

[0071] Example 1 - Zeta-potential measurements

[0072] Brine samples were prepared by adding 0 ppm, 500 ppm, or 1000 ppm of monosodium phosphate to each water source in Table 1.

[0073] Table 1. Composition of different brine

[0074] Contaminants were removed from crude oil samples by filtration and centrifugation. Oil / brine emulsions were prepared by adding oil drops to 5 mL of each brine. For calcite / brine suspensions, pure calcium carbonate disks with 99% by weight CaCO3 were used. Calcite purity was confirmed using X-ray diffraction (XRD). Calcite disks were ground under ambient conditions using a granite mill without the introduction of contaminants. For calcite / brine suspensions, 20 mL of each brine was mixed with a fine powder of 0.1 g of ground calcite, and then 5 mL of brine with ground calcite was transferred to a new vial containing 15 mL of calcite-free brine. The samples were sonicated after each step involving suspension to prevent particle agglomeration. In order to maintain consistent experimental conditions, the solid / liquid and liquid / liquid ratios were kept fixed.

[0075] Zeta-potential measurements were performed via phase analysis light scattering using a ZetaPALS instrument. At least two measurements were performed until consistent results were obtained. Two cells were used, one for the calcite / brine suspension and the other for the oil / brine emulsion.

[0076] Figure 2 and Figure 3 Zeta potential measurements at atmospheric conditions for the brine / calcite and crude oil / brine interfaces are shown separately for each brine sample prepared. Figure 2 It was shown that a concentration of 1000 ppm of sodium dihydrogen phosphate caused a significant decrease in the zeta potential value and shifted from a positive value of 7 mV for seawater without added NaH2PO4 to a negative value of -6 mV for seawater with 1000 ppm NaH2PO4. The pH of this brine dropped from about 7.5 for seawater without added NaH2PO4 to about 5.5 for seawater with 1000 ppm NaH2PO4.

[0077] like Figure 3 As shown, all measured zeta potentials at the oil / brine interfaces are negative. Addition of sodium dihydrogen phosphate changes the magnitude of the zeta potential.

[0078] These results indicate that sodium dihydrogen phosphate has a greater effect on the ζ-potential of the calcite / brine interface relative to the crude oil / brine interface, which has no obvious trend.

[0079] Example 2 - Contact angle measurement

[0080] Contact angle measurements were performed on seawater samples without and with 1000 ppm of sodium dihydrogen phosphate on a flat carbonate chip. The carbonate chip was saturated with brine, centrifuged, and aged in dead oil for four days. Next, the sample was installed in a chamber and injected with baseline brine. After the chamber was filled and no leakage was observed, an oil needle was used to place the droplet on the surface of the chip. When the test was performed, the pressure and temperature were maintained at 1000 psig and 70°C, respectively. A camera captured the surface with the droplet and a computer software was used to calculate the contact angle from the image.

[0081] The contact angle of seawater is 135 degrees, and the water contact angle of seawater with 1000 ppm NaH2PO4 is 90 degrees, respectively. Figure 4A and 4B As shown. The addition of sodium dihydrogen phosphate changes the ζ-potential of seawater / carbonate to negative (due to the adsorption of dihydrogen phosphate ions and hydrogen phosphate anions), thereby creating repulsion between the brine / carbonate and brine / crude oil interfaces. This electrostatic repulsion stabilizes the water film sandwiched between the oil droplet and the calcite surface and changes the wettability to more water-wet, resulting in additional oil recovery. The addition of NaH2PO4 reduces the contact angle by 45 degrees, changing the system to a more water-wet condition. Therefore, seawater with 1000 ppm NaH2PO4 is the most promising brine formulation for waterflooding because the ζ-potential of seawater / calcite is changed from positive to negative. 1000 ppm shows a strong effect on the ζ-potential while being safe and cost-effective to use in field operations.

[0082] Example 3 - Surface Modeling

[0083] A surface complexation model was used to describe the equilibrium state of ion adsorption based on specified surface reactions and to explain the observed behavior. To validate the model, experimental zeta potential values ​​were historically matched to the predicted model values ​​by manipulating the surface-reaction equilibrium constant.

[0084] In the surface complexation model, the concentration of adsorbed surface complexes (adsorbed ions) determines the overall surface charge:

[0085] in Surface charge density (C / m 2 ), F is the Faraday constant (96493.5 C / mol), S is the surface mass (g), and A is the specific surface area (m 2 / g), is the ionic charge, and is the adsorbed ion concentration (mol). Surface charge and surface-potential are related by the Gouy-Chapman model:

[0086]

[0087] in is the dielectric constant of vacuum , is the relative dielectric constant of water, is the surface-potential (V), R is the gas constant , T is the temperature (K), I is the salt water ionic strength (mol / l), and is the electrolyte ion charge which is assumed to be unity.

[0088] The site density of the calcite surface is 4.95 sites / nm 2 , while the site density on the crude oil surface is 0.47 sites / nm 2 The specific surface area of ​​calcite is 1 m 2 / g, while the specific surface area of ​​crude oil is 0.5 m 2 / g.

[0089] The intrinsic equilibrium constants (shown in Table 2) were considered as fitting parameters and varied in the SCM to match the measured zeta potential. The site density and specific surface area of ​​the considered surface were fixed.

[0090] The history match includes the surface reaction of the formation of dihydrogen phosphate ions trapped on top of divalent cations, as shown in Table 2.

[0091] Table 2. Complexation reactions on calcite surfaces involving divalent cations and dihydrogen phosphate

[0092]

[0093] Figure 5 A comparison between the experimental results and the modeled results is shown. The trend is qualitatively captured by the model.

[0094] The dihydrogen phosphate ions bind as a ternary component which mitigates the effect of the positive divalent cations (magnesium and calcium), resulting in an overall negative surface charge (with a corresponding negative zeta potential).

[0095] Other Implementations

[0096] It should be understood that although the invention has been described in conjunction with its detailed description, the foregoing description is intended to illustrate rather than limit the scope of the invention, which is defined by the scope of the appended claims. Other aspects, advantages and modifications are within the scope of the appended claims. For example, in some embodiments, in addition to or in place of salts of dihydrogen phosphate ions such as sodium dihydrogen phosphate and / or potassium dihydrogen phosphate, sodium chloride (NaCl) and / or sodium sulfate (Na2SO4) may also be used in the injection solution for water flooding.

Claims

1. A water flooding method, the method comprising: introducing a first injection solution comprising about 400 ppm to about 1000 ppm of dihydrogen phosphate ions into a subterranean formation; as well as introducing a second injection solution comprising dihydrogen phosphate ions into the subterranean formation; wherein the second injection solution has a concentration of dihydrogen phosphate ions of about 200 ppm to about 800 ppm and has a concentration of dihydrogen phosphate ions that is at least about 200 ppm lower than that of the first injection solution; and wherein at least a portion of the hydrocarbons present in the underground formation are displaced.

2. The method of claim 1, wherein at least one of the following is true: The pH of the first injection solution is from about 5.0 to about 5.5; or The pH of the second injection solution is about 5.0 to about 5.

5.

3. The method of claim 1, wherein at least one of the following is true: The first injection solution comprises seawater; or The second injection solution includes seawater.

4. The method of claim 1, wherein at least one of the following is true: the first injection solution is introduced into the underground formation in an amount of about 0.3 to about 0.5 pore volumes; or The amount of the second injection solution introduced into the underground formation is from about 0.3 to about 0.5 pore volumes.

5. The method of claim 1, wherein the first injection solution comprises about 1000 ppm of dihydrogen phosphate ions.

6. The method of claim 5, wherein at least one of the following is true: The first injection solution comprises seawater; or The second injection solution includes seawater.

7. The method of claim 1, further comprising introducing a squeeze solution into the underground formation, the squeeze solution comprising aquifer water, surface water, seawater, or a combination thereof.

8. The method of claim 7, wherein the amount of the squeeze solution introduced into the subterranean formation is from about 0.5 to about 1.0 pore volumes.

9. The method of claim 1, wherein the subsurface formation comprises a carbonate formation.

10. The method of claim 1, wherein the first injection solution is introduced after primary production of hydrocarbons from the subterranean formation.

11. The method of claim 1 , further comprising producing the hydrocarbons from the underground formation.

12. A method of water flooding, the method comprising: introducing a first injection solution comprising about 1000 ppm of dihydrogen phosphate ions into a subterranean formation; introducing a second injection solution comprising about 800 ppm of dihydrogen phosphate ions into the subterranean formation; introducing a third injection solution comprising about 600 ppm of dihydrogen phosphate ions into the subterranean formation; introducing a fourth injection solution comprising about 400 ppm of dihydrogen phosphate ions into the subterranean formation; as well as introducing a fifth injection solution comprising about 200 ppm of dihydrogen phosphate ions into the underground formation, Wherein at least one of the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and the fifth injection solution displaces at least a portion of hydrocarbons present in the underground formation.

13. The method of claim 12, wherein the pH of at least one of the first infusion solution, the second infusion solution, the third infusion solution, the fourth infusion solution, and the fifth infusion solution is about 5.0 to about 5.

5.

14. The method of claim 12, wherein at least one of the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and the fifth injection solution comprises seawater.

15. The method of claim 12, wherein an amount of at least one of the first injection solution, the second injection solution, the third injection solution, the fourth injection solution, and the fifth injection solution introduced into the underground formation is about 0.3 to about 0.5 pore volumes.

16. The method of claim 12, further comprising injecting a squeeze solution into the underground formation, the squeeze solution comprising aquifer water, surface water, seawater, or a combination thereof.

17. The method of claim 16, wherein the amount of the squeeze solution introduced into the subterranean formation is from about 0.5 to about 1.0 pore volume.

18. The method of claim 12, wherein the subsurface formation comprises a carbonate formation.

19. The method of claim 12, wherein the first injection solution is introduced after primary production of hydrocarbons from the subterranean formation.

20. The method of claim 12, further comprising producing the hydrocarbons from the underground formation.

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