An oil displacement agent, its preparation method and use

Abstract

This application belongs to the field of oil well enhancement technology, specifically relating to an oil displacement agent, its preparation method, and its application. The oil displacement agent comprises the following raw materials in the following mass percentages: 0.05% complexing agent, 0.05%-0.5% stabilizer, 0.05%-0.5% surfactant, and the balance water. The oil displacement agent of this application forms a multi-faceted synergistic oil displacement mechanism through the combination of a complexing system and a surfactant: "complexing reduces adhesion - interfacial tension decreases." The complexing agent selectively complexes calcium and magnesium ions in formation water, disrupting their bridging effect at the oil-solid interface and reducing the adhesion between crude oil and the reservoir surface. The complexing system can regulate the adsorption behavior of the surfactant at the oil-water interface, assisting in reducing the interfacial tension and enhancing the oil phase stripping and migration capabilities. This solves the problem of insufficient oil displacement power caused by traditional surfactants relying solely on interfacial tension reduction. The synergistic effect of both can efficiently strip oil films from rock surfaces and displace residual oil at blind ends, showing significant effects, especially in secondary oil recovery in old oilfields with high residual oil saturation.

Description

Technical Field

[0001] This invention belongs to the field of oil well production enhancement technology, specifically relating to an oil displacement agent, its preparation method, and its application. Background Technology

[0002] Oil displacement agents are specialized additives that enhance oil recovery by altering the physicochemical properties of oil reservoirs. Existing oil displacement agents for tight shale formations, due to their relatively high concentrations, readily adsorb and deposit their components within the micropores and throats of low-permeability reservoirs. Furthermore, formation water in tight shale reservoirs is generally rich in calcium and magnesium ions (Ca). 2+ and Mg 2+ The combined concentration of these substances often reaches 500-5000 mg / L. They readily react with carbonate, sulfate, or oil displacement agent components in formation fluids to form scale such as calcium carbonate and magnesium sulfate, clogging pore throats and fracture channels, thus reducing the coverage area of ​​the displacement fluid. At the same time, calcium and magnesium ions can damage the interfacial activity of the oil displacement agent, reduce the oil-water interfacial tension, and decrease the oil displacement effect. They cannot effectively remove crude oil adsorbed on the pore walls, resulting in limited recovery. Although existing technologies use complexing agents, such as EDTA and DTPA, to improve the above problems by adding complexing agents to the oil displacement agent, a high concentration (≥5%) is required to achieve an effective complexing effect, which does not meet the "low concentration, low damage" requirement of low-permeability reservoirs. Furthermore, some complexing agents can undergo ion exchange with reservoir clay minerals (such as montmorillonite), causing clay swelling and migration, further damaging the reservoir permeability. They are also prone to forming precipitates with other components of formation water, which can exacerbate the blockage.

[0003] Due to the low permeability of tight shale reservoirs (<0.1mD), conventional oil displacement agents are unable to effectively reduce the interfacial tension between oil and water and the displacement pressure, resulting in the displacement fluid being unable to efficiently penetrate into the deep reservoir, and the oil washing radius being limited to the vicinity of the wellbore. At the same time, the adsorption between crude oil and formation water and minerals on the pore wall is strong, and conventional complexing agents do not have oil displacement performance and are unable to disrupt their adsorption balance. The residual oil saturation is high, and the recovery rate improvement is generally less than 5 percentage points, which cannot meet the economic requirements of industrial mining. Summary of the Invention

[0004] This application provides an oil displacement agent, its preparation method, and its application, aiming to solve the problems of existing oil displacement agents causing reservoir blockage, secondary damage to the reservoir due to high concentrations, and low recovery rates.

[0005] The first aspect of this application provides an oil displacement agent comprising the following raw materials in the following mass percentages: 0.05% complexing agent, 0.05%-0.5% stabilizer, 0.05%-0.5% surfactant, and the balance being water.

[0006] According to some embodiments of the oil displacement agent described in this application, the raw materials include the following mass percentages: 0.05% complexing agent, 0.05% stabilizer, 0.2% surfactant, and the balance water.

[0007] According to some embodiments of the oil displacement agent described in this application, the complexing agent is a phenolic compound.

[0008] According to some embodiments of the oil displacement agent described in this application, the phenolic compound includes one or more of catechol, resorcinol, hydroquinone, and tea polyphenols.

[0009] According to some embodiments of the oil displacement agent described in this application, the stabilizer is sodium fatty alcohol polyoxyethylene ether sulfate.

[0010] According to some embodiments of the oil displacement agent described in this application, the surfactant is a petroleum sulfonate; According to some embodiments of the oil displacement agent described in this application, the water includes formation water.

[0011] The second aspect of this application provides a method for preparing the oil displacement agent described in the first aspect of this application, comprising the following steps: mixing a complexing agent, a stabilizer, a surfactant and water to obtain the oil displacement agent.

[0012] According to some embodiments of the preparation method of the oil displacement agent described in this application, the mixing temperature is 35-45°C and the mixing time is 40-70 min.

[0013] The third aspect of this application provides the application of the oil displacement agent described in the first aspect of this application or the oil displacement agent prepared by the method described in the second aspect of this application in oil reservoir development.

[0014] According to some embodiments of the application described in this application, the reservoir includes low-permeability oilfields and tight shale reservoirs.

[0015] According to some embodiments of the application described in this application, the permeability of the low-permeability oilfield is 0.1-50 mD, and the permeability of the tight shale reservoir is <0.1 mD.

[0016] The beneficial effects of this application include: 1. Synergistic optimization of interface performance, significantly enhanced oil displacement power: The oil displacement agent described in this application breaks through the traditional "single interface effect" oil displacement mode of surfactants. Through the combination of complexing system and surfactant, a multi-faceted synergistic oil displacement mechanism of "complexing to reduce adhesion - reducing interfacial tension" is formed. On the one hand, the selective complexation of calcium and magnesium ions in formation water by the complexing agent destroys their bridging effect between oil and solid interfaces, reducing the adhesion between crude oil and reservoir surface; on the other hand, the complexing system can regulate the adsorption behavior of surfactant at the oil-water interface, helping to reduce the oil-water interfacial tension to 10. -3Below mN / m, it enhances the oil phase stripping and migration capabilities, solving the problem of insufficient oil displacement power caused by the single reliance of traditional surfactants on interfacial tension reduction. The synergistic effect of the two can efficiently strip oil films from rock surfaces and displace residual oil at blind ends. Compared with conventional surfactant flooding, the crude oil recovery rate can be increased by 8%-15%, especially for old oilfields with high residual oil saturation after secondary oil recovery, which has a significant potential tapping effect.

[0017] 2. Excellent anti-interference ability and adaptability to complex reservoir environments: The complexing agent in the oil displacement agent described in this application can specifically complex calcium and magnesium ions in formation water, avoiding precipitation or inactivation of the surfactant due to ion cross-linking, and ensuring that the surfactant is effective at a salinity of 5×10⁻⁶. 4 ~2×10 5 It maintains good surface activity even in high-salt formations with a concentration of mg / L; at the same time, the complexation system can regulate the charge distribution of surfactant molecules, reduce their adsorption loss on the surface of different rock types such as sandstone and carbonate rocks, and prolong the effective action period of surfactants in formations. It is suitable for a variety of complex reservoir conditions such as high-salt, low-permeability and tight shale reservoirs.

[0018] 3. The oil displacement agent preparation process described in this application is simple and has both economic and environmental benefits: the complexing agent and surfactant used in this application are both industrially available raw materials, and the compounding process of the two does not require harsh conditions such as high temperature and high pressure, and the production cost is significantly reduced compared with traditional composite oil displacement agents; at the same time, the selected complexing agent and surfactant have good biocompatibility and biodegradability, with no risk of secondary pollution, which meets the requirements of green oilfield development; in addition, the complexing auxiliary system is compatible with existing oil displacement processes (such as water flooding and polymer flooding), without the need for large-scale modification of on-site equipment, and has high construction convenience, making it easy to promote and apply industrially. Attached Figure Description

[0019] Figure 1a This is a visualization of the microfluidic analysis results of the oil displacement agent described in Example 1 of this application; Figure 1b This is a visualization of the microfluidic analysis results of the oil displacement agent described in Comparative Example 9 of this application; Figure 2 These are core displacement data diagrams of the oil displacement agents described in Example 1 and Comparative Example 9 of this application; Figure 3a The low-field NMR one-dimensional T2 spectrum of the oil displacement agent described in Comparative Example 9 of this application; Figure 3b The low-field NMR one-dimensional T2 spectrum of the oil displacement agent described in Example 1 of this application; Figure 4a The low-field two-dimensional T1-T2 NMR spectra of the oil displacement agent and formation water flooding described in Comparative Example 9 of this application are shown. Figure 4a The left side represents formation water drive. Figure 4a The right side shows the oil displacement agent described in Comparative Example 9; Figure 4b The low-field two-dimensional T1-T2 NMR spectra of the oil displacement agent and formation water flooding described in Example 1 of this application are shown. Figure 4b The left side represents formation water drive. Figure 4b The right side shows the oil displacement agent described in Example 1; Figure 5 The images show low-field two-dimensional nuclear magnetic resonance (NMR) images of the oil displacement agents described in Example 1 and Comparative Example 9 of this application. Detailed Implementation

[0020] The embodiments of the present invention are described in detail below. These embodiments are exemplary and intended to explain the present invention, and should not be construed as limiting the present invention.

[0021] In this invention, the terms "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., refer to a specific feature, structure, material, or characteristic described in connection with that embodiment or example, which is included in at least one embodiment or example of the invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0022] This application provides an oil displacement agent comprising the following raw materials in the following mass percentages: 0.05% complexing agent, 0.05%-0.5% stabilizer, 0.05%-0.5% surfactant, and the balance being water.

[0023] The three components in the oil displacement agent described in this application work synergistically with each other. The complexing agent is responsible for preferentially forming complexes with calcium and magnesium ions, thereby reducing their bridging effect and adhesion at the oil-solid interface. The stabilizer is responsible for improving the stability of the formulation in the reservoir environment, preventing precipitation in the short term, and ensuring long-term effectiveness. The surfactant is responsible for causing oil droplet deformation, providing initial impetus to reduce the interfacial tension between oil and water and promote the spontaneous migration of oil droplets.

[0024] In some embodiments of this application, the raw materials include the following mass percentages: 0.05% complexing agent, 0.05% stabilizer, 0.2% surfactant, and the balance water. Specifically, the complexing agent in the oil displacement agent described in this application exhibits good complexing properties at 0.05%, preventing precipitation; the stabilizer at 0.05% effectively increases the stability of the system in the original reservoir environment; and the surfactant at 0.2% effectively reduces the oil-water interfacial tension. Furthermore, the concentrations of both are controlled within a certain range to avoid excessive cost.

[0025] In some embodiments of this application, the complexing agent is a phenolic compound.

[0026] In some embodiments of this application, the phenolic compounds include one or more of catechol, resorcinol, hydroquinone, and tea polyphenols.

[0027] In some embodiments of this application, the stabilizer is sodium fatty alcohol polyoxyethylene ether sulfate, which was purchased from Aladdin Reagent Company.

[0028] In some embodiments of this application, the surfactant is a petroleum sulfonate, and the oil displacement agent used in the embodiments of this application is a petroleum sulfonate produced and provided by a pharmaceutical company directly under Shengli Oilfield. In some embodiments of this application, the water includes formation water, because using raw formation water provided by the oilfield to dissolve the formulation agent can better match the actual reservoir production conditions and oil displacement performance.

[0029] This application embodiment also provides a method for preparing the oil displacement agent described in the first aspect of this application, comprising the following steps: mixing a complexing agent, a stabilizer, a surfactant and water to obtain the oil displacement agent.

[0030] In some embodiments of this application, a complexing agent is first added to the original formation water so that no precipitation will occur even if the formation water has a high salinity. Then, a stabilizer is added and the mixture is gently heated and stirred at 35-45°C to promote complete dissolution. Finally, a surfactant is added to obtain an oil displacement agent formulation that can guarantee both compatibility and oil displacement properties. This is due to the reasonable composition and content ratio of each component in the formulation.

[0031] In some embodiments of this application, the mixing temperature is 35-45°C, such as 35°C, 40°C, 45°C, etc., and the mixing time is 40-70 min, such as 40 min, 50 min, 55 min, 60 min, 70 min, etc.

[0032] This application also provides an application of the oil displacement agent described in the first aspect of this application or the oil displacement agent prepared by the method described in the second aspect of this application in oil reservoir development.

[0033] In some embodiments of this application, the reservoir includes low-permeability oil fields and tight shale reservoirs.

[0034] In some embodiments of this application, the permeability of the low-permeability oilfield is 0.1-50 mD, and the permeability of the tight shale reservoir is <0.1 mD.

[0035] The technical solution of this application will be further described below with reference to specific embodiments.

[0036] Example 1 A method for preparing an oil displacement agent includes the following steps: The oil displacement agent was obtained by mixing 0.05g catechol, 0.05g sodium fatty alcohol polyoxyethylene ether sulfate, 0.2g petroleum sulfonate and 99.7g formation water at 25°C for 60 minutes.

[0037] Example 2 The only difference between the preparation method of the oil displacement agent in Example 2 and that in Example 1 is that the amount of sodium fatty alcohol polyoxyethylene ether sulfate added during the preparation of the oil displacement agent in Example 2 is 0.1g.

[0038] Example 3 The only difference between the preparation method of the oil displacement agent in Example 3 and that in Example 1 is that the amount of sodium fatty alcohol polyoxyethylene ether sulfate added during the preparation of the oil displacement agent in Example 3 is 0.15g.

[0039] Example 4 The only difference between the preparation method of the oil displacement agent in Example 4 and that in Example 1 is that the amount of sodium fatty alcohol polyoxyethylene ether sulfate added during the preparation of the oil displacement agent in Example 4 is 0.2g.

[0040] Example 5 The only difference between the preparation method of the oil displacement agent in Example 5 and that in Example 1 is that the amount of petroleum sulfonate added during the preparation of the oil displacement agent in Example 5 is 0.05g.

[0041] Example 6 The only difference between the preparation method of the oil displacement agent in Example 6 and that in Example 1 is that the amount of petroleum sulfonate added during the preparation of the oil displacement agent in Example 6 is 0.1g.

[0042] Example 7 The only difference between the preparation method of the oil displacement agent in Example 7 and that in Example 1 is that the amount of petroleum sulfonate added during the preparation of the oil displacement agent in Example 7 is 0.3g.

[0043] Comparative Example 1 The only difference between the preparation method of the oil displacement agent in Comparative Example 1 and Example 1 is that the amount of catechol added during the preparation of the oil displacement agent in Comparative Example 1 is 0.1g.

[0044] Comparative Example 2 The only difference between the preparation method of the oil displacement agent in Comparative Example 2 and that in Example 1 is that the amount of catechol added during the preparation of the oil displacement agent in Comparative Example 2 is 0.01g.

[0045] Comparative Example 3 The only difference between the preparation method of the oil displacement agent in Comparative Example 3 and that in Example 1 is that ethylenediaminetetraacetic acid is used instead of catechol in the preparation process of the oil displacement agent in Comparative Example 3.

[0046] Comparative Example 4 The only difference between the preparation method of the oil displacement agent described in Comparative Example 4 and that in Example 1 is that resorcinol is used instead of catechol in the preparation process of the oil displacement agent described in Comparative Example 4.

[0047] Comparative Example 5 The only difference between the preparation method of the oil displacement agent described in Comparative Example 5 and that in Example 1 is that tetrasodium diacetate of glutamate is used instead of catechol in the preparation process of the oil displacement agent described in Comparative Example 5.

[0048] Comparative Example 6 The only difference between the preparation method of the oil displacement agent described in Comparative Example 6 and that in Example 1 is that sodium dodecylbenzenesulfonate is used instead of petroleum sulfonate in the preparation process of the oil displacement agent described in Comparative Example 6.

[0049] Comparative Example 7 The only difference between the preparation method of the oil displacement agent described in Comparative Example 7 and that in Example 1 is that 3-sulfopropyltetradecyl dimethyl betaine is used instead of petroleum sulfonate in the preparation process of the oil displacement agent described in Comparative Example 7.

[0050] Comparative Example 8 The only difference between the preparation method of the oil displacement agent described in Comparative Example 8 and that in Example 1 is that a cationic Gemini-type surfactant is used instead of petroleum sulfonate in the preparation process of the oil displacement agent described in Comparative Example 8.

[0051] Comparative Example 9 The only difference between the preparation method of the oil displacement agent described in Comparative Example 9 and that in Example 1 is that catechol was not used in the preparation process of the oil displacement agent described in Comparative Example 9.

[0052] Comparative Example 10 The only difference between the preparation method of the oil displacement agent described in Comparative Example 10 and Example 1 is that sodium fatty alcohol polyoxyethylene ether sulfate was not used in the preparation process of the oil displacement agent described in Comparative Example 10.

[0053] Comparative Example 11 The only difference between the preparation method of the oil displacement agent described in Comparative Example 11 and Example 1 is that the oil displacement agent described in Comparative Example 11 does not use petroleum sulfonate as a raw material in its preparation process.

[0054] Study on the application effect of the oil displacement agents described in Examples 1-7 and Comparative Examples 1-11 of this application: Test method: (1) Oil-water interfacial tension (mN / m) The test was conducted using a rotating drop ultra-low interfacial tension meter: First, the oil displacement agent to be tested was injected into the glass tube, and a very small amount of oil droplets were spin-coated onto the tube wall. Then, the tube was filled with oil displacement agent and sealed. The temperature was set to 70℃ and the rotation speed was set to 5000 rpm. After the parameters met the standard, the test was continued for 30 minutes, and the final data was recorded.

[0055] (2) Oil-solid interface current and duration The test was performed using a digital source meter: First, the glass tube (10 cm long, 0.5 mm inner diameter) was filled with the oil-repelling agent to be tested. A tiny amount of oil droplet was slowly pushed into one end of the glass tube using a syringe with an outer diameter of 0.3 mm. After filling the glass tube with oil-repelling agent, it was sealed. A silver wire electrode head was connected to both ends. The entire experimental platform was then covered with a heat insulation cover. After heating to 70°C, the change in current over time was measured.

[0056] (3) Visualizing microfluidic displacement efficiency The experiment was conducted using a visual microfluidic displacement platform: Heterogeneous fluidic glass chips with an inner diameter distribution range of 60-120 micrometers were selected. The chips were first rinsed with raw formation water, then crude oil was injected to displace the formation water, demonstrating that the oil-water distribution within the chip closely resembled that of a real oil reservoir. The chips were saturated in a 70°C oven for one day before being placed in a chip fixture for microfluidic displacement. Initially, formation water was used for displacement for 15 minutes, then switched to surfactant displacement for another 15 minutes. ImageJ software was used to calculate the displacement efficiency of the oil-displacing agent based on the photographs. The injection flow rate was 1 μL / min.

[0057] (4) Stabilization time of reservoir environment formulation Testing was conducted using a constant temperature chamber: the oil displacement agent to be tested was placed in a 70°C constant temperature chamber and sealed for storage, and the longest time during which the system remained stable without precipitation was recorded.

[0058] The results are shown in Table 1.

[0059] Table 1

[0060] As can be seen from Table 1: (1) According to Examples 2-4, as the concentration of stabilizer (sodium fatty alcohol polyoxyethylene ether sulfate) increases, the system becomes more stable in the reservoir environment, increasing from the original 7 days to 10 days. However, it has a negative impact on the reduction of oil-water interfacial tension, weakens the ability of oil droplets to extend and deform, strengthens the adhesion between the oil and solid interface, increases the difficulty of migration, and thus worsens the displacement efficiency.

[0061] (2) As shown in Examples 5-7, the concentration change of the surfactant (petroleum sulfonate) has a small effect on stability, but a very large effect on the oil-water interfacial tension, exceeding the effects of the stabilizer and complexing agent. When the surfactant concentration decreases, the oil-water interfacial tension increases significantly, resulting in a severe weakening of the oil droplet's ability to extend and deform, further shrinking the ion transport channels between the oil and solid interfaces, leading to a significant decrease in both current intensity and duration, and increased difficulty in oil droplet migration, thus resulting in very poor displacement efficiency. As for the oil displacement performance improved after the concentration increased, the improvement was small, and the stability decreased slightly. That is, when the amount of petroleum sulfonate added is 0.2g, the performance of the oil displacement agent is better.

[0062] (3) According to Comparative Examples 1-2, the concentration change of the complexing agent (catechol) tends to affect stability. When the concentration increases, the stability improves slightly and the oil displacement performance decreases slightly, both with very small amplitudes. However, when the concentration decreases, the stability decreases significantly, and the performance of assisting in reducing the oil-water interfacial tension also decreases. The weakened ability of oil droplets to extend and deform also leads to a decrease in current intensity and duration, thus reducing the displacement efficiency. Therefore, when the amount of catechol added is 0.05g, the oil displacement agent obtained has better oil displacement performance.

[0063] (4) According to Comparative Examples 3-5, the type of complexing agent (catechol) has a greater impact on stability. All three complexing agents will cause a significant decrease in system stability, which is far less than that of catechol. As a result, their performance in assisting to reduce the interfacial tension between oil and water will also decrease significantly. After the adhesion and force of oil droplets on the reservoir surface increase, they will be more difficult to be stretched and deformed. The current intensity and duration will decrease significantly, and the displacement efficiency will decrease by a very large margin.

[0064] (5) According to Comparative Examples 6-8, the change in the type of surfactant (petroleum sulfonate) tends to affect the performance of the oil-water interface. The ability of these three surfactants to reduce the tension of the oil-water interface is far less than that of petroleum sulfonate, making it more difficult for oil droplets to be displaced. Therefore, after the degree of stretching and deformation decreases significantly, the current intensity and duration will also decrease significantly.

[0065] (6) According to Comparative Example 9, if a complexing agent (catechol) is not used, there is a lack of complexing effect on calcium and magnesium ions in formation water. Therefore, calcium and magnesium ions can not only reduce the effect of other components, but also increase the adhesion of oil droplets on the reservoir surface due to their large amount remaining between the oil and solid interfaces. Therefore, it is difficult to work with surfactants to reduce the oil-water interfacial tension, resulting in low displacement efficiency. At the same time, the stability of the system will also decrease significantly because calcium and magnesium ions will not be effectively complexed.

[0066] (7) According to Comparative Example 10, if the stabilizer (sodium fatty alcohol polyoxyethylene ether sulfate) is not used, although the interfacial tension between oil and water increases slightly and the oil displacement performance decreases, these effects are not as significant as the significant decrease in stability. Due to the lack of stabilizing effect after complexing calcium and magnesium ions, calcium and magnesium ions undergo severe precipitation with the phenolic hydroxyl groups of the complexing agent under high temperature conditions, and the cycle is even shortened to 2 days. Therefore, if this formula is to achieve long-term stable efficacy, the addition of a stabilizer is absolutely necessary.

[0067] (8) According to Comparative Example 11, if the surfactant (petroleum sulfonate) is not used, although the stability of the system is almost unchanged, the performance of the oil-water interface is severely weakened, the interfacial tension increases significantly, the oil droplets can hardly spontaneously extend and deform, and the ion transport channels between the oil and solid interfaces are narrowed significantly. Therefore, the displacement efficiency, current intensity and duration are the worst among all proportions. So if this formula wants to truly achieve oil displacement, it absolutely cannot do without this petroleum sulfonate.

[0068] In conclusion, all three components are indispensable.

[0069] 1. Study on the oil displacement performance of the oil displacement agents described in Example 1 and Comparative Example 9 of this application. Visual microfluidic analysis of the oil displacement agents described in Example 1 and Comparative Example 9 of this application (test method as described in Experiment 3 above, each tested in parallel three times), the test results are as follows: Figure 1a and Figure 1b As shown.

[0070] from Figure 1a and Figure 1b As can be seen from the above, the oil displacement agent described in Example 1 of this application has a better oil displacement effect.

[0071] 2. Core displacement analysis of the oil displacement agents described in Example 1 and Comparative Example 9 of this application Analysis method: (1) Core selection and pretreatment Artificially synthesized quartz sand cemented rock, 10cm in length and 2.5cm in diameter (with smooth, crack-free end faces to prevent fluid flow), was selected. The cleaned core was then placed in a vacuum drying oven for degassing at 105℃ and a vacuum of -0.095MPa for 24 hours to thoroughly remove free water and gas from the core pores. The core length (L) and diameter (D) were then measured using calipers, and the core volume V was calculated. core Accurate to 0.01cm 3 .

[0072] (2) Porosity (φ) and permeability (k) test Porosity was determined using the vacuum saturation method: The dried rock core was placed in a vacuum saturation apparatus and evacuated for 3 hours (vacuum degree -0.095 MPa). Simulated formation water was then injected, and the core was soaked for 12 hours. The mass (m³) after saturation with water was then measured. wet ), calculate porosity φ: φ=(m wet - m dry ) / (ρ w × V core )×100% Where, m dry ρ represents the mass (g) of the dried core. w To simulate the density of formation water (g / cm³) 3 ), V core The volume of the rock core is φV, which is the product of the porosity and the core volume. core This will be represented as Vφ in Table 1. 。

[0073] Permeability was measured using a gas permeameter (nitrogen as the medium), and the absolute permeability was determined according to Darcy's law. k=(2QμL) / (AΔP) Where Q is the nitrogen flow rate (cm) 3 / s), μ is the viscosity of nitrogen (mPa). s), A is the cross-sectional area of ​​the rock core (cm²) 2 ΔP is the pressure difference (MPa) between the two ends of the core, and the permeability range of the target core is required to be consistent with that of the reservoir.

[0074] (3) Experimental setup and calibration Displacement pump: Constant pressure mode high-pressure pump (pressure range 0-50MPa, flow accuracy ±0.01mL / min), used to control the injection rate.

[0075] Intermediate containers: 3 high-pressure intermediate containers (500 mL volume, 50 MPa pressure resistance) to store simulated water, simulated oil, and oil displacement agent respectively. The top of the containers is equipped with an exhaust valve (for degassing).

[0076] Core holder: Hasler type core holder (pressure resistant 50MPa), with fluororubber sealing ring, the confining pressure is provided by a high pressure constant pressure pump (the confining pressure is 1-2MPa higher than the injection pressure to prevent fluid from flowing out of the gap between the core and the holder).

[0077] Detection system: pressure sensor (accuracy ±0.001MPa, installed at the inlet and outlet of the rock core), flow meter (dual verification of volumetric method and mass method), constant temperature chamber (temperature control range 25-150℃, accuracy ±0.5℃).

[0078] Product liquid collection system: separatory funnel (for oil-water phase separation), electronic balance (accuracy 0.001g, for recording product liquid mass), sample bottle (for collecting product liquid for component analysis).

[0079] Pressure sensor calibration: Calibrate using a standard pressure gauge, with an error ≤0.5%; Flow pump calibration: Verify flow accuracy by weighing the mass of water discharged over a certain period of time (error ≤1%).

[0080] System leak test: Close all outlet valves, inject nitrogen into the system to 1.2 times the maximum test pressure (e.g., 30MPa), maintain for 2 hours, and the pressure drop is ≤0.1MPa to be considered qualified.

[0081] Pipeline cleaning: The entire pipeline system is flushed with simulated formation water (flow rate 5 mL / min, time 30 min) to remove impurities and residual air from the pipeline.

[0082] Experimental phase: It is necessary to simulate reservoir conditions such as temperature, pressure, and flow rate, and operate according to the "saturation-displacement-endpoint" process, focusing on recording dynamic data such as pressure and produced liquid volume.

[0083] (4) Saturation stage Saturated simulated water (establishing bound water): Load the pretreated core into the holder, connect the pipeline, and turn on the constant temperature chamber to the reservoir temperature (e.g., 70℃), maintaining the temperature for 2 hours; turn on the simulated water intermediate container and displacement pump, injecting simulated water at a constant rate of 0.1 mL / min until water continuously flows out of the core outlet without air bubbles, continuously injecting twice the pore volume (PV), then turn off the pump; weigh the total mass of the core after saturation with water, verify the porosity (error ≤ 2% from the pretreatment stage measurement), and determine the bound water volume, which is also equivalent to the core pore volume Vφ (Vφ = φ × V core ).

[0084] Saturated simulated oil (establishing initial oil saturation): Switch the pipeline to the intermediate simulated oil container and inject simulated oil at a constant rate of 0.1 mL / min to displace the simulated water in the core. Continuously collect the produced liquid (aqueous phase) and record the volume of produced water every 10 minutes until the water content in the produced liquid is ≤0.5% (considered as the bound water saturation reaching stability), then turn off the pump.

[0085] Calculate the initial oil saturation (S) oi ):S oi =(V o injected – V w produced ) / Vφ×100% Among them, V o injected Total volume of injected oil (cm³) 3 ), V w produced Total volume of produced water (cm³) 3 ), requires Soi =60%-80% (consistent with the actual oil saturation of the reservoir).

[0086] Stabilization phase: Allow the oil to stand at the reservoir temperature for 12 hours to allow the crude oil to come into full contact with the core and bound water, reaching adsorption-desorption equilibrium.

[0087] (5) Displacement test operation (staged displacement, "first formation water flooding → then oil flooding") Formation water drive stage (baseline recovery determination): Switch the pipeline to the simulated water intermediate container, set the displacement pump to constant speed mode, and convert the injection rate according to the actual reservoir flow velocity (Darcy velocity v = 0.1 m / d in the core, corresponding to a flow rate of 0.05 mL / min, ensuring laminar flow). Record the injection pressure (ΔP) and injection volume (V) every 5 minutes. injected Collect the produced liquid every 10 minutes, separate the oil and aqueous phases using a separatory funnel, and record the volume of produced oil (V). o produced ), produced water volume (V) w produced ).

[0088] Endpoint: When the water cut of the produced fluid is ≥98%, or the recovery rate increases by ≤0.5% within three consecutive PV injection volumes, waterflooding is stopped, and the formation waterflood recovery rate (E) is calculated. w =(Cumulative oil production / V) oi )×100%, V oi =S oi ×Vφ,V oi (This refers to the initial oil content), which is the ORF in Table 1 below. FW (%).

[0089] (6) Oil displacement agent displacement stage (core test stage) Pipeline switching: Use a displacement pump to drain the residual simulated water in the pipeline (inject 10 mL of oil displacement agent) to avoid fluid mixing affecting the oil displacement effect. Maintain the injection rate consistent with the water drive stage (or adjust according to the experimental design), and keep the confining pressure and temperature constant; if it is necessary to simulate reservoir shear conditions (such as a high-shear environment near the production well), apply shearing action to the oil displacement agent through a built-in shearing device (such as a rotary shear apparatus) (shear rate 2000 s). -1 The injection time was 0 min, and the core was injected again. The recording frequency was increased to once every 2 min of injection pressure, and the produced fluid was collected once every 5 min. In addition to recording the oil and water volumes, an extra sample of the produced fluid was collected (for determining the concentration of the oil displacement agent and emulsion stability).

[0090] Low-permeability oilfields in my country are classified into four categories: ordinary low-permeability (10-50 mD), ultra-low permeability (1-10 mD), super-low permeability (0.1-1 mD), and tight shale (<0.1 mD). To more realistically reflect the effect in low-permeability reservoirs, this experimental example selected two core samples: one from ultra-low permeability and the other from tight shale. Furthermore, to test whether the formulation containing the complexing agent (the oil displacement agent described in Example 1) could function in a real reservoir environment, this experimental example challenged the tight shale core with the lowest permeability with the formulation containing the complexing agent.

[0091] Endpoint: When the water cut of the produced fluid reaches 98% again, or the injected displacement agent volume reaches 10 PV, displacement is stopped, and the oil recovery rate (E) is calculated. dis =(Oil produced during displacement stage / V) oi ()×100%), which is the ORF in Table 1 below. SF (%). Subtract the preceding formation water drive recovery rate (ORF). FW (%), which is EOR (%), meaning the oil recovery rate increased by the oil displacement agent compared to formation water. The results are shown in Table 2 and... Figure 2 As shown.

[0092] Table 2

[0093] Precautions: Maintain a stable temperature in the constant temperature chamber throughout the experiment (fluctuation ≤ 0.5℃) to avoid changes in fluid viscosity and interfacial tension caused by temperature variations; if the injection pressure suddenly increases, it may be due to core blockage (such as oil displacement agent agglomeration or impurity deposition), and the experiment must be stopped and the core replaced; if the pressure suddenly drops, it may be due to core rupture or seal failure, and the clamp seal must be checked; ensure that the separating funnel separates completely (oil phase on top, water phase at the bottom) to avoid unclear oil-water stratification leading to volume measurement errors; keep high-pressure equipment away from personnel, and wear protective glasses and gloves during operation; after the experiment, release the system pressure slowly (pressure release rate ≤ 0.5MPa / min) to avoid sudden pressure changes damaging the equipment.

[0094] Note: In Table 2, L, D, dry weight, wet weight, and V... core Vφ, porosity, permeability, and other physical properties of the rock core itself are classified.

[0095] From Table 2 and Figure 2As can be seen, due to the low permeability of tight shale, conventional displacement is difficult, resulting in consistently low recovery rates during the formation water stage. However, in the latter half, the oil displacement efficiency of the formulation containing the complexing agent (the oil displacement agent described in Example 1 of this application) is consistently higher than that of the formulation without the complexing agent (the oil displacement agent described in Comparative Example 9 of this application). Although the final recovery rate is only two percentage points higher, this result was achieved under more severe reservoir conditions, and the final recovery rate is close to 80%, which is nearly 20 percentage points higher than conventional formation water displacement (60.6%). This represents a significant production for a block, proving that the formulation with the complexing agent is more effective in displacing oil in tight shale reservoirs with the lowest permeability. This also verifies the credibility of the mechanism proposed earlier, that is, by complexing, adhesion can be reduced, micropore permeation can be enhanced, and interfacial tension can be reduced, thereby synergistically promoting the extension and migration of oil droplets.

[0096] 3. The effect of the oil displacement agent described in Example 1 and Comparative Example 9 of this application on reservoir pore size Research methods: Low-field NMR was used for one-dimensional T2 spectroscopy, two-dimensional T1-T2 spectroscopy, and imaging analysis. (1) Magnetic field strength: The commonly used magnetic field strength for low-field NMR is 0.5T (corresponding to the proton resonance frequency of 24MHz). 0.5T is selected for core pore analysis (taking into account both resolution and penetration depth), and 1T is selected for fluid relaxation dynamics research (to improve the signal-to-noise ratio).

[0097] (2) Selection of acquisition sequence: The CPMG (Carr-Purcell-Meiboom-Gill) sequence is used for conventional T2 test, which is suitable for most EOR systems (core, fluid, three-phase mixed system). Its advantages are rapid acquisition and strong resistance to magnetic field inhomogeneity. The CPMG-LED (Longitudinal Eddy Delay) sequence is used for synchronous testing of fluid diffusion coefficient. The diffusion coefficient D is obtained at the same time as the T2 test, which can be used to analyze the inhibitory effect of oil displacement agent on fluid diffusion (such as gel oil displacement agent reducing the diffusion coefficient of aqueous phase). The improved CPMG sequence (with pulse interval compensation) is used under low temperature and high pressure conditions to avoid magnetic field drift caused by temperature / pressure changes and ensure signal stability.

[0098] (3) Error elimination: The signal from the empty sample tube (without sample) is collected as the background and subtracted from the original sample signal to eliminate instrument electronic noise; Savitzky-Golay filtering (window size 8 points) or moving average filtering (window size 3~5 points) is used to smooth signal fluctuations, but over-filtering should be avoided to prevent peak distortion (preserving the authenticity of peak position and peak area); Since the baseline may drift at the end of the original signal (due to magnetic field inhomogeneity or sample adsorption), resulting in integral area error, baseline correction is required. Polynomial fitting (1st to 3rd order polynomial) or linear baseline correction can be used to flatten the signal baseline to the noise level to ensure accurate peak area calculation; The signal tail is truncated according to T2max (truncate the signal at T210s to avoid noise interference), and finally the signal intensity is normalized to the 0~1 range to facilitate T2 comparison of different samples (such as spectrum superposition analysis before and after displacement).

[0099] (4) T2 inversion (core step) The low-field NMR T2 test yields an echo attenuation signal (time-domain data), which needs to be converted into a T2 relaxation time distribution spectrum (T2 spectrum) using an inversion algorithm, i.e., the solution is required.

[0100] Where S(t) is the time-domain signal intensity, f(T2) is the T2 relaxation time distribution function (T2 spectrum), e is the electron, t is the relaxation time, and d is the mathematical integral of the T2 variable, which can be converted into the variation trend of reservoir pore size, as shown in Figure 3.

[0101] As can be seen from Figure 3, after displacement using the formulation containing the complexing agent of this application, the proportion of micropores increases (marked by large circles), indicating that it can be applied to the displacement of bound oil phases in tight shale and also has a certain improvement on reservoir connectivity; macropores are completely fluid-free (marked by small circles), indicating that while acting on micropores, it also has a good displacement effect on macropores, avoiding uneven displacement coverage.

[0102] (5) Next, let's look at the relevant principles and data processing methods of the T1-T2 two-dimensional spectrum. This representation is mainly used to analyze the changes in oil and water distribution. The steps regarding magnetic field strength, acquisition sequence selection, and error elimination are the same as before, so they will not be repeated here. The only difference is that the original data of the two-dimensional spectrum is a three-dimensional matrix of "T1 delay time - echo time - signal strength", which needs to be converted into a two-dimensional distribution spectrum of "T1-T2-signal strength" (contour map / pseudo-color map) through an inversion algorithm. The core equation is:

[0103] in, S ( τ i , tj The original signal strength is 0. f(T 1 ，T 2 ) Let τ be the two-dimensional relaxation distribution function (spectral signal intensity) from T1 to T2, where e represents an electron, d is a part of this function that specifies the content to be integrated, T1 represents the longitudinal relaxation time, T2 represents the transverse relaxation time, and τ is the latitudinal relaxation time. i and t j These represent the signal strength and relaxation time at the acquisition point, respectively.

[0104] (6) Inversion parameter optimization (avoiding false peaks and low resolution) The T1 / T2 interval range is: T1∈[0.01ms, 10s], T2∈[0.01ms, 10s] (covering the full relaxation interval of the EOR system); for the nano-oil displacement agent system, it can be extended to T1 / T2∈[0.001ms, 10s] to capture the rapid relaxation signal of water adsorbed on the surface of nanoparticles.

[0105] Regularization parameter (λ): Two-dimensional inversion requires simultaneous optimization of λ in both T1 and T2 dimensions, determined by the "L-curve method" (to balance fitting error and smoothness), typically λ∈

[10] . -4 , 10 -2 (If λ is too small, false peaks are likely to appear; if it is too large, peak fusion is likely to occur.)

[0106] Number of iterations: CONTIN algorithm iterates 100 times, discrete inversion iterates 200 times, to ensure convergence (total signal strength error between two adjacent iterations <1%).

[0107] Node density: 50 nodes in T1 dimension and 80 nodes in T2 dimension (the more nodes, the higher the resolution, but the computational cost increases exponentially).

[0108] The above are the points to note. After completing these steps, you will obtain the corresponding scores and data, as shown in Figure 4. Depend on Figure 4a and Figure 4b Data Tables 3 and 4 were obtained from this.

[0109] Table 3

[0110] Table 4

[0111] As can be seen from Figure 4 and Tables 3 and 4, the oil displacement agent described in Comparative Example 9 showed a smaller increase in capillary bound water, a slight decrease in movable oil in the orifices, and almost no change in bound oil, resulting in a small change in the final oil-water saturation. In contrast, the oil displacement agent described in Example 1 of this application showed a larger increase in capillary bound water, with a large amount of movable and bound oil in the orifices being displaced, resulting in a larger change in the final oil-water saturation. This further demonstrates that for unconventional reservoirs with the lowest permeability, such as tight shale, the oil displacement effect after adding the complexing agent does not decrease but rather increases.

[0112] (7) Finally, two-dimensional imaging was performed on the core samples from different stages. Combined with the previous data analysis, all the results are clear at a glance. The analysis method is as follows: The hydrogen nucleus density (ρ) and T2 relaxation time of different fluids (oil / water / displacement agent) are different, resulting in significant differences in imaging signal intensity (S). The core relationship is: where ρ is the hydrogen nucleus density (crude oil ρ≈0.9 g / cm³). 3 Water ρ = 1 g / cm³ 3 The oil displacement agent colloid ρ≈1.05 g / cm³ 3 TR is the repetition time, and TE is the echo time.

[0113] The core of data processing for low-field 2D NMR imaging is to "convert raw k-space data into a visualized image and extract spatial distribution and quantitative indicators". The process is divided into "preprocessing → image reconstruction → image analysis → quantitative calculation", as shown below.

[0114] Raw data preprocessing (k-space data optimization): The raw imaging data is stored as a "k-space matrix" (with the same size as the image matrix, such as 128×128). The center of the k-space corresponds to the low-frequency components (overall signal strength) of the image, and the edges correspond to the high-frequency components (spatial details). The purpose of preprocessing is to remove noise, correct distortion, and ensure the quality of the reconstructed image.

[0115] Image reconstruction (k-space → spatial domain image): The core is two-dimensional Fourier transform (2D FFT), which transforms the "frequency-phase" data in k-space into an "xy position-signal intensity" image in the spatial domain. Then, through geometric correction, artifact removal, and image segmentation, the image is divided into "oil phase region, water phase region, oil displacement agent region, and pore region (no signal)".

[0116] Fusion of T2-weighted and relaxation images: "Spatial location-T2 relaxation" data can be acquired synchronously through CPMG imaging sequences. The T2 relaxation time is mapped to color (e.g., short T2 → blue, long T2 → red) to generate a "T2-weighted pseudo-color image" to achieve synchronous visualization of "spatial distribution + fluid state" (e.g., red area is movable oil, blue area is bound water, and green area is oil displacement agent).

[0117] Quantitative calculation (EOR core performance index extraction): Based on the segmented image, quantitative indicators related to spatial distribution and content are extracted, and the results are as follows: Figure 5 As shown.

[0118] from Figure 5 As can be seen from the data, after displacement with the oil displacement agent described in Example 1 of this application, the tight shale core is clearer and cleaner, indicating a better displacement effect; this further proves that the complexing agent can be applied to tight shale reservoirs with the lowest permeability.

[0119] Although the above embodiments have been shown and described, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Any changes, modifications, substitutions and variations made to the above embodiments by those skilled in the art are within the protection scope of the present invention.

Claims

1. An oil displacement agent, characterized in that, The raw materials include the following percentages by weight: complexing agent 0.05%, stabilizer 0.05%-0.5%, surfactant 0.05%-0.5%, and the balance being water.

2. The oil displacement agent according to claim 1, characterized in that, The raw materials include the following percentages by weight: complexing agent 0.05%, stabilizer 0.05%, surfactant 0.2%, and the balance being water.

3. The oil displacement agent according to claim 1, characterized in that, The complexing agent is a phenolic compound; Preferably, the phenolic compounds include one or more of catechol, resorcinol, hydroquinone, and tea polyphenols.

4. The oil displacement agent according to claim 1, characterized in that, The stabilizer is sodium fatty alcohol polyoxyethylene ether sulfate.

5. The oil displacement agent according to claim 1, characterized in that, The surfactant is a petroleum sulfonate.

6. The oil displacement agent according to claim 1, characterized in that, The water includes groundwater.

7. The method for preparing the oil displacement agent according to any one of claims 1-6, characterized in that, The process includes the following steps: mixing a complexing agent, a stabilizer, a surfactant, and water to obtain the oil displacement agent.

8. The method for preparing the oil displacement agent according to claim 7, characterized in that, The mixing temperature is 35-45℃, and the mixing time is 40-70 minutes.

9. The application of the oil displacement agent according to any one of claims 1-6 or the oil displacement agent obtained by the preparation method according to any one of claims 7-8 in oil reservoir development; Preferably, the reservoir includes low-permeability oilfields and tight shale reservoirs.

10. The application according to claim 9, characterized in that, The permeability of the low-permeability oilfield is 0.1-50 mD, and the permeability of the tight shale reservoir is <0.1 mD.

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