A method to enhance oil recovery

Abstract

This invention provides a method for improving oil recovery. The method includes the following steps: 1) determining the size of micro-nano bubbles and the volume percentage of micro-nano bubbles in a first injection fluid based on formation characteristics, and then preparing a first injection fluid containing micro-nano bubbles; 2) injecting the first injection fluid containing micro-nano bubbles into the formation for displacement operations.

Description

Technical Field

[0001] This invention provides a method for improving oil recovery, particularly a method for improving oil recovery containing micro-nano bubbles. Background Technology

[0002] In oil and gas reservoir development, the utilization of the elastic energy of fluids and rocks within the reservoir is called primary oil recovery. Primary oil recovery typically only recovers about 10% of the original reserves. The development stage involving water and gas injection to replenish and displace formation energy is called secondary oil recovery. Water injection (also known as waterflooding) is the most widely used reservoir development method. For conventional reservoirs with high permeability and good homogeneity, waterflooding oil recovery rates can reach 40% to 50%, or even higher. However, for low-permeability and heavy oil reservoirs, oil recovery rates are often below 40%, with a large amount of crude oil remaining in the formation as residual oil. The oil recovery rate of waterflooding is controlled by various factors such as reservoir characteristics, fluid properties, waterflooding method, and well pattern. However, the low sweep efficiency and low waterflooding efficiency caused by reservoir heterogeneity are the main influencing factors. Therefore, to improve the effectiveness of waterflooding, measures that can expand the sweep efficiency and improve the oil displacement efficiency are often adopted.

[0003] To improve oil recovery, the swept volume and oil displacement efficiency of the displacement medium can be increased by injecting an aqueous solution containing chemical agents; this stage is called tertiary oil recovery. Chemical flooding is the most commonly used tertiary oil recovery method.

[0004] However, water flooding or chemical flooding suffers from small swept volume, low oil displacement efficiency, and high operating costs. Therefore, a new type of oil displacement method is needed. Summary of the Invention

[0005] One invention provides a method for improving oil recovery, comprising the steps of:

[0006] 1) Determine the size of the micro-nano bubbles and the volume percentage of the micro-nano bubbles in the first injection fluid based on the formation characteristics, and then prepare the first injection fluid containing micro-nano bubbles;

[0007] 2) The first injection fluid containing micro-nano bubbles is injected into the formation to carry out displacement operations.

[0008] In one specific embodiment, the size of the micro-nanobubbles and the volume percentage of the micro-nanobubbles in the first injected fluid are determined based at least on the following: formation temperature, formation pressure, formation fluid properties in the formation, and rock pore structure in the formation.

[0009] In one specific embodiment, the rock pore structure includes permeability, porosity, pore radius, permeability range, and rock fracture pressure.

[0010] In one specific embodiment, the formation fluid properties include the viscosity of the formation fluid.

[0011] In one specific embodiment, the factors used to determine the size of the micro-nanobubbles and the volume percentage of the micro-nanobubbles in the first injected fluid also include the following: surface temperature, surface pressure, wellhead temperature, wellhead pressure, and formation thickness.

[0012] In one specific embodiment, the formation fluid properties also include the density of the formation fluid and the type of residual oil.

[0013] In one specific embodiment, the median particle size of the micro-nano bubbles is smaller than the average rock pore radius in the formation.

[0014] In one specific embodiment, in step 2), a second injection fluid without micro-nano bubbles and a first injection fluid containing micro-nano bubbles are alternately injected into the formation.

[0015] In one specific embodiment, a second injection fluid without micro-nano bubbles is first injected into the formation, and then the first injection fluid containing micro-nano bubbles is injected into the formation.

[0016] In one specific embodiment, the first injection fluid and the second injection fluid are independently water or a viscosity-reducing solution.

[0017] In one specific embodiment, the viscosity-reducing solution is selected from surfactant solutions, polymer solutions, or saline solutions.

[0018] In one specific embodiment, the surfactant solution contains a surfactant capable of reducing the interfacial tension between oil and water, a surfactant capable of altering wettability, or a surfactant capable of reducing the viscosity of crude oil.

[0019] In one specific embodiment, the surfactant is at least one selected from alkyl sulfonates, aryl sulfonates, rhamnolipids, and betaine-type surfactants.

[0020] In one specific embodiment, the surfactant is rhamnolipid and / or sodium octadecyl toluenesulfonate.

[0021] In one specific embodiment, the particle size of the micro-nano bubbles is 40 to 60 μm, and the volume percentage of the micro-nano bubbles in the first injected fluid containing the micro-nano bubbles is more than 1%, preferably 5% to 30%.

[0022] In one specific embodiment, the gas used to prepare the micro-nano bubbles is selected from at least one of nitrogen, carbon dioxide, air, or natural gas.

[0023] In one specific embodiment, the method is used in tertiary oil recovery processes.

[0024] In one specific implementation, the pressure at the wellhead P < P 岩石破裂压力 -P 地层压力 -ρgH, where ρ is the density of the injected fluid and H is the height of the injected fluid.

[0025] In one specific implementation, the wellhead pressure does not exceed 20 MPa.

[0026] In one specific implementation, the wellhead pressure does not exceed 10 MPa.

[0027] The term "micro-nano bubble" in this invention refers to a bubble with a diameter between tens of micrometers and hundreds of nanometers when it is generated, which is between micrometer bubbles and nano bubbles.

[0028] The beneficial effects of this invention are:

[0029] Experiments have shown that using injection fluids containing micro- and nano-bubbles for displacement operations can effectively improve oil recovery rates. Unbound by any theory, it can be assumed that after the injection fluid containing micro-nano bubbles is injected into the formation, the following six main effects will occur: (1) The micro-nano bubbles dispersed in the injection fluid are released from the water, generating cavitation, which acts inside the rock pores, releasing a large amount of heat and power, changing the occurrence state of crude oil, and improving the displacement efficiency; (2) Due to the large number of micro-nano bubbles in the injection fluid, the apparent viscosity of the injection fluid will increase significantly and the density will decrease significantly, which will significantly reduce the gravity separation of oil and water in the injected formation and increase the sweep volume of the injected water; (3) After the micro-nano bubbles are released from the injection fluid, they are easy to be adsorbed on the surface of the rock pores, occupy the pore volume, change the direction of the liquid flow, and increase the micro sweep volume and displacement efficiency; (4) The presence of micro-nano bubbles can increase the diffusion rate of chemical agents, provide power for the mass transfer of chemical agents, and thus improve the effect of the chemical agent aqueous solution; (5) In medium and high permeability formations, the water phase permeability is significantly reduced and the oil phase permeability is increased; (6) The gas drive mechanism is generated after the bubbles collapse and form a continuous gas phase.

[0030] This invention addresses the shortcomings of water-flooding and chemical-flooding methods in crude oil development, such as low sweep efficiency, low displacement efficiency, and high cost. It utilizes an injection fluid containing micro-nano bubbles to enhance and improve the effects of water-flooding and chemical-flooding, further increasing oil recovery. The technical solution of this invention is particularly suitable for enhancing oil recovery in late-stage water-flooding reservoirs and for chemical-flooding in heavy oil reservoirs. This invention not only significantly increases the sweep volume of the injected fluid and improves displacement efficiency but also increases the diffusion rate of the chemical agents in the injected fluid, thereby significantly improving oil recovery through the synergistic effect of its components. Furthermore, the equipment and apparatus required for this invention are simple, have minimal impact on oilfield surface facilities, are easy to operate, and can significantly reduce costs. It can meet the enhanced oil recovery needs of different types of water-flooding and chemical-flooding reservoirs, and is particularly suitable for chemical-flooded conventional reservoirs and chemical-flooded heavy oil reservoirs. Attached Figure Description

[0031] Figure 1 A flowchart for determining the injection parameters of micro / nano bubbles.

[0032] Figure 2 The injection flowchart.

[0033] Figure 3 This is a schematic diagram of the connection of a micro / nano bubble generator. Detailed Implementation

[0034] The present invention will be further described below with reference to the embodiments. However, the embodiments of the present invention are merely illustrative examples and should not be construed as limiting the present invention under any circumstances.

[0035] Example 1

[0036] An oil reservoir has a burial depth of 1670 meters, an original formation pressure of 21 MPa, a formation temperature of 67℃, an average porosity of 28%, and an average permeability of 610 × 10⁻⁶. -3 μm 2 The reservoir has an average thickness of 7m, is a positive rhythmic reservoir, and has a permeability gradient of 4.2. Water injection development was achieved using a seven-point well network with a well spacing of 240m, resulting in an oil production rate of 1.5%. The injected water rapidly surged along the high-permeability zone at the bottom, causing a rapid increase in water cut and deteriorating development efficiency. To improve water drive performance, it was decided to add micro-nano bubbles to the injected water to increase the water drive sweep efficiency and improve oil displacement efficiency. The specific plan is as follows:

[0037] (1) Based on formation temperature, pressure, fluid properties, and rock pore structure characteristics, the median particle size of the micro / nano bubbles was determined to be 50 micrometers, and the volume of the micro / nano bubbles accounted for 10% of the total volume of the micro / nano bubble water. Nitrogen was used as the gas. The formation temperature was 67℃; the formation pressure was 21 MPa; the formation crude oil was heavy oil with a viscosity of 360 mPa·s. The rock pore structure characteristics were determined through laboratory analysis of core samples taken from the reservoir, as follows: the average pore radius of the rock was 31 micrometers, the average pore radius of the top low-permeability section was 24 micrometers, the average fracture pressure of the rock was 47 MPa, the average porosity was 28%, and the average air permeability was 610 × 10⁻⁶. -3 μm 2 The permeability gradient is 4.2. Furthermore, the average wellhead injection temperature is 30 degrees Celsius, and the wellhead pressure is required to not exceed 10 MPa. Based on these conditions, according to the attached... Figure 1 The process shown determines the injection parameters.

[0038] (2) Micro-nano bubble water is prepared using a nitrogen generation device, a pressurization device, and a micro-nano bubble production device installed on the ground, and then injected into the formation through an injection device and a wellhead pump. The injection process follows... Figure 2 The connection is shown in the diagram. The micro-nano bubbles are generated through pressurized dissolved gas method and micropore method. A schematic diagram of the connection of the micro-nano bubble generator is shown below. Figure 3 As shown. The generation of micro / nano bubbles is achieved using the following method... Figure 3 The microporous media described herein are either flat plate-shaped (micro / nanoporous plates) or columnar microporous media (micro / nanoporous columns). Both the micro / nanoporous plates and columns are hollow and are placed inside a water injection pipeline. They are then sequentially connected to a pressure regulator, a gas flow meter, a regulating valve, and a high-pressure gas storage tank via pipelines that pass through the walls of the water injection pipeline.

[0039] (3) Based on the formation temperature and pressure conditions, the valve size is adjusted using the regulating valve in the micro / nano bubble generator, the gas flow rate is measured using a gas flow meter, and the gas pressure is adjusted to be higher than the water injection pipeline pressure using a pressure regulator. In this embodiment, the gas injection pressure is adjusted to be 0.3 MPa higher than the water injection pipeline pressure. In the generated micro / nano bubble water, the total volume of micro / nano bubbles accounts for 10% of the total volume of micro / nano bubble water.

[0040] (4) Injecting 200m per day 3 A certain amount of micro-nano bubble water is injected.

[0041] (5) 70 days after injection, the wellhead pressure of the injection well increased by 1.4 MPa, the water cut of the oil well decreased by an average of 4.2%, and the daily oil production of a single well increased by 2.6 tons.

[0042] (6) Through numerical simulation calculations, the recovery rate of the block is expected to be increased by more than 5% compared with the original water drive development by using water containing micro-nano bubbles.

[0043] Example 2

[0044] A heavy oil reservoir has five producing wells arranged in a row-and-column pattern with a well spacing of 120m. The reservoir is 900m deep, with an initial formation pressure of 9.6MPa, a formation temperature of 55℃, an average porosity of 32%, an average air permeability of 2200mD, an average effective reservoir thickness of 4.8m, and an average crude oil viscosity of 4400mPa·s. After six rounds of steam huff and puff, the overall water cut rose to 75%, leading to well shutdown and production halt. The recovery rate will be improved by a combined flooding method using micro / nano bubble water and viscosity reducer solution. The specific implementation plan is as follows:

[0045] (1) Based on geological and reservoir studies, two wells were selected as injection wells, and the other three wells were selected as production wells, forming an injection-production well network. The median particle size of the micro-nano bubbles was determined to be 50 micrometers (average rock pore radius was 56 micrometers) based on formation temperature, pressure, fluid properties, and rock pore structure characteristics. The volume of the micro-nano bubbles accounted for 5% of the total volume of the micro-nano bubble water. Nitrogen was used. The formation temperature was 55℃; the formation pressure was 9.6 MPa; the formation crude oil was heavy oil with an average viscosity of 4400 mPa·s. The rock pore structure characteristics were determined through laboratory analysis of core samples taken from the reservoir, specifically as follows: the average pore radius of the rock was 87 μm, the average pore radius of the top low-permeability section was 56 μm, the average fracture pressure of the rock was 32 MPa, the average porosity was 32%, and the average air permeability was 2200 × 10⁻⁶. -3 μm 2 The permeability gradient is 3.1. In addition, the average temperature of the water injected at the wellhead is 60 degrees Celsius, and the wellhead pressure is required to not exceed 20 MPa.

[0046] (2) and (3) are the same as in Example 1. The difference from step (3) is that in this example, the air injection pressure is adjusted to be 0.5 Pa higher than the water injection pipeline pressure. In the generated micro-nano bubble water, the total volume of micro-nano bubbles accounts for 5% of the total volume of micro-nano bubble water.

[0047] (4) Prepare a 0.5 wt% aqueous solution of rhamnolipin to obtain a viscosity reducer solution.

[0048] (5) The operation sequence is as follows: first inject 0.05 PV of viscosity-reducing solution, then inject 0.1 PV of micro / nano bubble water; repeat twice, for a total injection of 0.15 PV of viscosity-reducing solution and 0.3 PV of micro / nano bubble water. The total volume of viscosity-reducing solution and micro / nano bubble water injected per well per day is 120 m³. 3 .

[0049] (6) After the above-mentioned sluice gate is completed, the subsequent water drive is carried out.

[0050] Forty days after injection, the production well showed increased oil production and decreased water cut. It is expected that the recovery rate will be increased by 13% after the project is completed.

[0051] Example 3

[0052] A certain heavy oil reservoir has five production wells at a depth of 900 meters. The wells are arranged in a row-and-column pattern with a spacing of 120 meters. The formation temperature is 55℃, the original formation pressure is 9.6 MPa, the average porosity is 32%, and the average air permeability is 2200 × 10⁻⁶. -3 μm 2 The reservoir has an average effective thickness of 4.8 m, a permeability gradient of 3.1, and a crude oil viscosity of 4400 mPa·s. After six rounds of steam huff and puff, the overall water cut rose to 75%, leading to well shutdown and production stoppage. To improve oil recovery, a viscosity-reducing solution was prepared as a micro-nano bubble aqueous solution for displacement. The specific implementation plan is as follows:

[0053] (1) Based on the formation temperature, pressure, fluid properties, and rock pore structure characteristics, the median particle size of the micro / nano bubbles was determined to be 50 micrometers (average rock pore radius was 56 micrometers), and the volume of the micro / nano bubbles accounted for 30% of the total volume of the micro / nano bubble water; nitrogen was used as the gas. The formation temperature was 55℃; the formation pressure was 9.6 MPa; the formation crude oil was heavy oil with an average viscosity of 4400 mPa·s; the average pore radius of the rock was 87 μm, the average pore radius of the top low-permeability section was 56 μm, the average fracture pressure of the rock was 32 MPa, the average porosity was 32%, and the average air permeability was 2200 × 10⁻⁶. -3 μm 2 The permeability gradient is 3.1. In addition, the average temperature of the water injected at the wellhead is 60 degrees Celsius, and the wellhead pressure is required to not exceed 20 MPa.

[0054] (2) and (3) are the same as in Example 1. The difference is that water is replaced with a viscosity-reducing solution, thereby generating a viscosity-reducing solution containing micro / nanobubbles. The viscosity-reducing solution is a 0.3 wt% aqueous solution of sodium octadecyl toluenesulfonate. In this example, the gas injection pressure is adjusted to be 0.5 MPa higher than the water injection line pressure. In the generated viscosity-reducing solution containing micro / nanobubbles, the micro / nanobubbles account for 30% of the total volume of the viscosity-reducing solution.

[0055] (4) A viscosity-reducing solution containing micro-nano bubbles is injected into the formation through an injection device for continuous displacement.

[0056] The production well became effective 40 days after injection, and it is expected to eventually increase the recovery rate by 15%.

[0057] While the present invention has been described with reference to specific embodiments, those skilled in the art will understand that various changes can be made without departing from the true spirit and scope of the invention. Furthermore, numerous modifications can be made to the subject, spirit, and scope of the invention to suit specific situations, materials, material compositions, and methods. All such modifications are included within the scope of the claims of the present invention.

Claims

1. A method for enhancing oil recovery, comprising the steps of: 1) Determine the size of micro-nano bubbles and the volume percentage of micro-nano bubbles in the first injected fluid based at least on the formation temperature, formation pressure, formation fluid properties in the formation, and rock pore structure in the formation, and then prepare the first injected fluid containing micro-nano bubbles; 2) The first injection fluid containing micro-nano bubbles is injected into the formation to carry out displacement operations.

2. The method according to claim 1, characterized in that, The rock pore structure includes permeability, porosity, pore radius, permeability range, and rock fracture pressure.

3. The method according to claim 1, characterized in that, The formation fluid properties include the viscosity of the formation fluid.

4. The method according to claim 1, characterized in that, The formation fluid properties also include the density of the formation fluid and the type of residual oil.

5. The method according to claim 1, characterized in that, Factors used to determine the size of micro- and nanobubbles and their volume percentage in the first injected fluid include: surface temperature, surface pressure, wellhead temperature, wellhead pressure, and formation thickness.

6. The method according to claim 2, characterized in that, The median particle size of the micro-nano bubbles is smaller than the average rock pore radius in the formation.

7. The method according to claim 1, characterized in that, In step 2), a second injection fluid without micro-nano bubbles and a first injection fluid containing micro-nano bubbles are alternately injected into the formation.

8. The method according to claim 1, characterized in that, In step 2), a second injection fluid without micro-nano bubbles is first injected into the formation, and then a first injection fluid containing micro-nano bubbles is injected into the formation.

9. The method according to any one of claims 1 to 8, characterized in that, The first injection fluid and the second injection fluid are independently water or a viscosity reducer solution.

10. The method according to claim 9, characterized in that, The viscosity-reducing solution is selected from surfactant solutions, polymer solutions, or brine.

11. The method according to claim 10, characterized in that, The surfactant solution contains surfactants that can reduce the interfacial tension between oil and water, surfactants that can change wettability, or surfactants that can reduce the viscosity of crude oil.

12. The method according to claim 11, characterized in that, The surfactant is at least one of alkyl sulfonates, aryl sulfonates, rhamnolipids, and betaine-type surfactants.

13. The method according to claim 11, characterized in that, The surfactant is rhamnolipid and / or sodium octadecyl toluenesulfonate.

14. The method according to any one of claims 1 to 8, characterized in that, The micro-nano bubbles have a particle size of 40 to 60 μm, and the volume percentage of the micro-nano bubbles in the first injected fluid containing the micro-nano bubbles is more than 1%.

15. The method according to claim 14, characterized in that, The volume percentage of the micro-nano bubbles in the first injected fluid containing the micro-nano bubbles is 5% to 30%.

16. The method according to any one of claims 1 to 8, characterized in that, The gas used to prepare the micro-nano bubbles is selected from at least one of nitrogen, carbon dioxide, air, or natural gas.

17. The method according to any one of claims 1 to 16, characterized in that, The method is used in tertiary oil recovery processes.

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