A displacement method for greatly improving recovery ratio of low-permeability oil reservoirs

Abstract

The present application belongs to the technical field of oilfield development chemical flooding enhanced oil recovery, and particularly relates to a displacement method for greatly improving the recovery ratio of low-permeability oil reservoirs. The displacement method comprises: first water flooding, miscible solvent solution flooding, and second water flooding; the miscible solvent solution flooding comprises: injecting a miscible solvent solution into a low-permeability oil reservoir, wherein the miscible solvent solution is a solution containing small-molecule compounds; and the small-molecule compounds are selected from at least two of methanol, ethanol, propanol, methyl ether, ethyl ether, and acetone. The method brings chemical agents into the oil reservoir through the miscible solvent aqueous solution, the miscible solvent diffuses through the oil-water interface into the oil phase, expands and starts residual oil, and the residual oil is displaced by subsequent water injection, thereby greatly improving the recovery ratio of crude oil. Indoor core displacement experiments show that, with an injection amount of 0.5 PV, the recovery ratio of crude oil in a low-permeability oil reservoir can be improved by 20-55% after water flooding, indicating that the miscible solvent oil displacement technology is an effective means for greatly improving the recovery ratio of low-permeability oil reservoirs.

Description

Technical Field

[0001] This invention belongs to the field of enhanced oil recovery technology using chemical flooding in oilfield development, and more specifically, relates to a displacement method for significantly improving the recovery rate of low-permeability reservoirs. Background Technology

[0002] Petroleum is crucial to national energy security and has a significant impact on national defense, economic development, and people's daily lives. Currently, most of my country's oilfields are in the mid-to-late stages of development, with water cut rising rapidly, sometimes exceeding 90%, making existing technologies insufficient to meet their needs. With the continuous development of the petroleum industry and the deepening of extraction, many high-quality oil reservoirs have already experienced oil depletion. Against this backdrop, low-permeability reservoirs and other difficult-to-develop reserves will become a key focus for my country's petroleum industry. Low-permeability reservoirs generally have a permeability of 10-50 mD, with some reservoirs having a permeability of 1-10 mD, or even below 1 mD, making waterflooding development difficult. Due to the small pore size, poor interpore connectivity, and complex formation structure of low-permeability reservoirs, fluid flow is hindered, and traditional displacement methods struggle to achieve good development results, resulting in very high production costs and difficulties. Currently, domestic and international low-permeability reservoirs mainly employ water injection, gas injection, and active water injection for development, with good results achieved in field applications. However, due to the prevalent problems of prominent interlayer contradictions and strong heterogeneity in low-permeability reservoirs, water and gas channeling are significant, resulting in generally low recovery rates (<25%). Based on water / gas injection, surfactants can further improve the recovery rate of ultra-low permeability reservoirs by enhancing percolation, a fact confirmed in field trials. However, surfactants are sensitive to temperature and salinity, and have a short field shelf life, limiting their application. Statistics show that China's low-permeability oil resources amount to 53.7 billion tons, accounting for 49% of total resources. The difficulty in developing low-permeability oilfields poses a significant challenge to stable oil production. Therefore, how to develop low-permeability oilfields is an urgent problem for petroleum workers. Developing an oil displacement technology that can improve the recovery rate of crude oil in low-permeability reservoirs is of great significance to the future development of the petroleum industry.

[0003] Chinese patent application 201610763500.X describes a method for endogenous microbial oil recovery in low-permeability reservoirs. This method screens activators of biopolymer-producing functional bacteria and biosurfactant-producing functional bacteria. Field trials are conducted in three phases: injection of biopolymer-producing functional bacteria activators, injection of biosurfactant-producing functional bacteria activators, and normal water injection. The field trial results show that this method effectively saves on the amount of injection agents used and significantly improves the field recovery rate. Chinese patent application 201010227128.3 describes a method for improving water-driven oil recovery in low-permeability reservoirs. This method involves preparing a mixed aqueous solution of surfactants, foam stabilizers, and water, and then injecting this solution into the reservoir along with gas. Chinese patent application 201210241250.5 describes a method for enhancing oil recovery in low-permeability sandstone reservoirs. A flexible microgel deep displacement agent is injected via a metering pump into the water distribution pipeline of a late-stage fracturing water injection well in an ultra-low permeability sandstone reservoir. After injection, the oil recovery rate is significantly improved. Chinese patent application 202010224596.9 describes a composite oil displacement agent for enhancing oil recovery in low-permeability reservoirs and its preparation method. This agent reduces oil-water interfacial tension, alters reservoir wettability, and has advantages such as low adsorption amount on the reservoir rock surface, minimal adsorption loss, low concentration, low cost, and high oil displacement rate.

[0004] For decades, mixed-solvent enhanced oil recovery (EOR) technology has been a focus of research in the oil and gas industry. In 1960, Gatlin and Slobod proposed a miscible displacement mechanism of isopropanol and methanol dissolved in water-driven slugs in porous media, suggesting that mixed solvents could significantly improve oil recovery, mainly due to the high dependence of the mixed solvent on the phase state of the system in the reservoir fluid and the differences in solubility in different phases. In 1961, Taber, Kamath, and Reed studied the phase characteristics of alcohol-oil-brine systems and the differences in solvent displacement characteristics with different partition coefficients. Block and Donovan first proposed the concept of recovery and reinjection of mixed solvents in produced fluids in 1961. Summary of the Invention

[0005] The purpose of this invention is to address the problems of poor oil recovery and difficult injection in existing chemical flooding technologies for low-permeability reservoirs. This invention provides a mixed solvent technology for improving the oil recovery of low-permeability reservoirs. This technology involves adding a micro-polar small molecule compound that is soluble in both the aqueous and oil phases to the injection water to prepare a mixed solvent aqueous solution. Injecting this mixed solvent aqueous solution into low-permeability reservoirs not only improves injection performance but also significantly increases the oil recovery rate of low-permeability reservoirs.

[0006] To achieve the above objectives, the present invention provides a displacement method for significantly improving the recovery rate of low-permeability reservoirs, the displacement method comprising: a first water flood, a mixed solvent solution flood, and a second water flood;

[0007] Mixed solvent solution flooding includes: injecting a mixed solvent solution into a low-permeability reservoir, wherein the mixed solvent solution is a solution containing small molecule compounds;

[0008] The small molecule compound is selected from at least two of methanol, ethanol, propanol, dimethyl ether, diethyl ether, and acetone.

[0009] As a preferred embodiment, the small molecule compound is selected from at least two of methanol, propanol, and acetone.

[0010] As a further preferred embodiment, the small molecule compound includes methanol.

[0011] As a further preferred embodiment, the small molecule compound is dimethyl ether and:

[0012] Propanol and / or acetone.

[0013] As the optimal approach, the amount of propanol and / or acetone used is 7-10 mL relative to 100-120 mL of dimethyl ether.

[0014] As a preferred embodiment, the concentration of the small molecule compound in the solution is 5-30% v / v.

[0015] As a preferred embodiment, the solvent for the solution of the small molecule compound is water and / or an aqueous salt solution.

[0016] As a preferred embodiment, the saline solution has a mineralization of 3000-300000 mg / L and a concentration of divalent calcium and magnesium ions of 0-5000 mg / L.

[0017] As a preferred option, the injection volume of the mixed solvent solution is 0.3-0.6 PV.

[0018] According to the present invention, the conditions satisfied by the low-permeability reservoir include:

[0019] Permeability ≤ 50mD.

[0020] The beneficial effects of this invention are:

[0021] This invention introduces a chemical agent into the reservoir using a mixed solvent aqueous solution. The mixed solvent diffuses across the oil-water phase interface into the oil phase, expands, and activates the residual oil. Subsequent water injection then displaces the residual oil, significantly improving oil recovery. This mixed solvent-based enhanced oil recovery technology relies primarily on phase-driven processes and is applicable to a wide range of reservoir conditions, including diverse geological formations, fluid properties, and reservoir conditions. Therefore, its application scope far exceeds that of any existing enhanced oil recovery technology. Indoor core displacement experiments show that an injection volume of 0.5 PV can increase oil recovery in low-permeability reservoirs by 20-55% after waterflooding, demonstrating that mixed solvent flooding technology is an effective means to significantly improve oil recovery in low-permeability reservoirs.

[0022] Other features and advantages of the present invention will be described in detail in the following detailed description section. Detailed Implementation

[0023] Preferred embodiments of the invention will now be described in more detail. While preferred embodiments of the invention are described below, it should be understood that the invention can be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that the invention will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art.

[0024] This invention provides a displacement method to significantly improve the recovery rate of low-permeability reservoirs. The displacement method includes: a first water flood, a mixed solvent solution flood, and a second water flood.

[0025] Mixed solvent solution flooding includes: injecting a mixed solvent solution into a low-permeability reservoir, wherein the mixed solvent solution is a solution containing small molecule compounds;

[0026] The small molecule compound is selected from at least two of methanol, ethanol, propanol, dimethyl ether, diethyl ether, and acetone. Appropriate small molecule compounds and ratios can be selected based on reservoir conditions and parameters such as temperature, salinity, and crude oil properties, according to the system's solubility and partition coefficients in the oil-water phase.

[0027] According to this invention, a certain amount of a micro-polar, small-molecule mixed solvent, soluble in both the aqueous and oil phases, is added to water injected into the reservoir in a suitable proportion for laboratory experiments or field applications. The mixed solvent is dissolved in the aqueous phase to form a solution, which is then introduced into the deep reservoir via injection water. Because the mixed solvent has greater solubility in the oil phase, when it comes into contact with the oil phase in the reservoir, the solvent in the aqueous solution will cross the oil-water interface, transfer mass into the crude oil, and dissolve in it. After dissolving in the oil phase, the mixed solvent expands the crude oil, increasing reservoir energy, while simultaneously reducing crude oil viscosity and increasing the flowability of crude oil in the formation. This injection of the mixed solvent can activate residual oil in the reservoir and form an oil wall, which is then displaced by subsequent water injection, improving oil recovery. Furthermore, subsequent water injection can recover and recycle the mixed solvent, thereby reducing chemical costs and improving economic efficiency. Oil recovery in mixed-solvent flooding is primarily driven by phase dynamics, making it applicable to a wide range of reservoir conditions. It can be used in various geological reservoirs, with different fluid properties and reservoir conditions (pressure, temperature, and salinity), thus its application scope far exceeds that of any existing tertiary oil recovery technology. Mixed-solvent flooding technology can be implemented as a tertiary oil recovery technology in existing waterflooding projects, or it can be applied from the outset in a new secondary oil recovery waterflooding project, both of which can improve oil recovery rates. Especially in low-permeability reservoirs, mixed-solvent flooding technology offers significant technical advantages and economic benefits compared to other enhanced oil recovery technologies.

[0028] As a preferred embodiment, the small molecule compound is selected from at least two of methanol, propanol, and acetone.

[0029] As a further preferred embodiment, the small molecule compound includes methanol.

[0030] As a further preferred embodiment, the small molecule compound is dimethyl ether, and: propanol and / or acetone. According to the invention, in one specific embodiment, the small molecule compound is methanol + propanol; in another specific embodiment, the small molecule compound is methanol + acetone; and in yet another specific embodiment, the small molecule compound is methanol + acetone + propanol.

[0031] As the optimal solution, the amount of propanol and / or acetone used is 7-10 mL relative to 100-120 mL of dimethyl ether, such as 100 mL of dimethyl ether + 7 mL of propanol, or 100 mL of dimethyl ether + 10 mL of acetone.

[0032] As a preferred embodiment, the concentration of the small molecule compound in the solution is 5-30% v / v.

[0033] As a preferred embodiment, the solvent for the solution of the small molecule compound is water and / or an aqueous salt solution.

[0034] As a preferred embodiment, the saline solution has a mineralization of 3000-300000 mg / L and a concentration of divalent calcium and magnesium ions of 0-5000 mg / L.

[0035] As a preferred option, the injection volume of the mixed solvent solution is 0.3-0.6 PV, such as 0.5 PV.

[0036] According to the present invention, the conditions satisfied by the low-permeability reservoir include:

[0037] Permeability ≤ 50mD.

[0038] In the embodiments of the present invention:

[0039] The core samples used in the core displacement experiments were Bailey sandstone, 30 cm long, with an inner diameter of 2.5 cm, a permeability of 1–50 mD, and a pore volume of 3–20 mL. The entire displacement experiment was conducted in a digitally controlled temperature chamber, with a fluid injection rate of 0.02–0.1 mL / min, a back pressure at the produced end of 2–3 MPa, and an experimental system temperature of 40–120 °C. The oil used was simulated crude oil from a low-permeability reservoir, with a viscosity comparable to that of the underground crude oil, ranging from 1.0 to 10.0 mPa·s.

[0040] The general procedure for core displacement experiments is as follows: First, the experimental core is evacuated and saturated with simulated formation brine. Then, water is used to establish the initial oil saturation of the core. After aging at reservoir temperature for more than 24 hours, water flooding (or direct mixed solvent aqueous solution flooding) is carried out. After 2 PV water flooding, 0.5 PV of mixed solvent aqueous solution is injected. Then (or after simmering the well for 2-12 hours), 1.5-2 PV of subsequent water flooding is injected. The production crude oil volume, water content, and changes in injection and production pressure at different stages are measured and recorded. Finally, the crude oil recovery rate and the water content of the produced fluid are calculated.

[0041] Example 1

[0042] This example illustrates a displacement method for significantly improving the recovery rate of low-permeability reservoirs.

[0043] First, prepare a 100,000 mg / L simulated formation water solution using NaCl. Take 350 mL of the simulated formation water solution and place it in a 500 mL stainless steel intermediate container. Add 7 mL of propanol and 100 mL of dimethyl ether to the container from the bottom using a metering pump, and adjust the pressure in the intermediate container to 2.5 MPa from the top. Let it stand at room temperature for more than 48 hours to ensure uniform mixing. The prepared mixed solution is ready for use.

[0044] A 30cm layer of Bailey sandstone with a gas-side permeability of 45mD was placed in a core holder. An annular pressure of 10MPa was applied, and the simulated reservoir temperature was 100℃. After evacuation for 4 hours, 100,000 mg / L of simulated formation water was injected into the core, with a measured injection volume of 22.0 mL. The core porosity was 15%. After aging for 2 hours, simulated crude oil at 4 mPa·s was injected into the core at a rate of 0.05 mL / min to establish initial oil saturation. The outlet back pressure was 2.4 MPa. After injecting 2PV of simulated crude oil, 9.5 mL of water was pumped out, resulting in an initial oil saturation of 44.2%. The core was then aged at the reservoir temperature for 48 hours. Water flooding with 100,000 mg / L simulated formation water at an injection rate of 0.1 mL / min for 2PV yielded 3.3 mL of crude oil, resulting in a waterflood recovery rate of 34.7%. Once the produced fluid water cut exceeded 98%, a mixed solvent flooding solution was used, with the injection rate remaining constant at 0.5 PV. This was followed by water flooding until no more oil was produced at the outlet, with a subsequent water flooding injection volume of 1.6 PV. The mixed solvent flooding and subsequent water flooding yielded 3.8 mL of produced crude oil. The mixed solvent flooding after water flooding increased the oil recovery by 40% (compared to continuous water flooding), achieving a total oil recovery of 74.7%.

[0045] Example 2

[0046] This example illustrates a displacement method for significantly improving the recovery rate of low-permeability reservoirs.

[0047] First, prepare a 100,000 mg / L simulated formation water solution using NaCl. Take 350 mL of the simulated formation water solution and place it in a 500 mL stainless steel intermediate container. Add 7 mL of propanol and 100 mL of dimethyl ether to the container from the bottom using a metering pump, and adjust the pressure in the intermediate container to 2.5 MPa from the top. Let it stand at room temperature for more than 48 hours to ensure uniform mixing. The prepared mixed solution is ready for use.

[0048] A 30cm layer of Bailey sandstone with a gas-side permeability of 37mD was placed in a core holder. An annular pressure of 10MPa was applied, and the simulated reservoir temperature was 100℃. After evacuation for 4 hours, simulated formation water of 100,000 mg / L was injected into the core, with a measured injection volume of 21.7 mL and a core porosity of 14.7%. After aging for 2 hours, simulated crude oil of 4 mPa·s was injected into the core at a rate of 0.05 mL / min to establish initial oil saturation. The outlet back pressure was 2.4 MPa. After injecting 2PV of simulated crude oil, 9.0 mL of water was discharged, resulting in an initial oil saturation of 41.5%. The core was then aged at the reservoir temperature for 48 hours. Water flooding with 100,000 mg / L simulated formation water at an injection rate of 0.1 mL / min for 2PV resulted in the recovery of 3.52 mL of crude oil, achieving a waterflood recovery rate of 39.1%. Once the water cut of the produced fluid exceeded 98%, a mixed-solution flooding was initiated, maintaining the same injection rate at a rate of 0.5 PV. After a 10-hour well-sinking period, subsequent water flooding was used until no more oil was produced at the outlet, with a subsequent water flooding injection rate of 1.6 PV. The mixed-solution and subsequent water flooding yielded 4.86 mL of produced crude oil. The mixed-solution flooding after water flooding increased the oil recovery by 54%, achieving a total oil recovery of 93.1%.

[0049] Example 3

[0050] This example illustrates a displacement method for significantly improving the recovery rate of low-permeability reservoirs.

[0051] First, prepare a 100,000 mg / L simulated formation water solution using NaCl. Take 350 mL of the simulated formation water solution and place it in a 500 mL stainless steel intermediate container. Add 7 mL of propanol and 100 mL of dimethyl ether to the container from the bottom using a metering pump, and adjust the pressure in the intermediate container to 2.5 MPa from the top. Let it stand at room temperature for more than 48 hours to ensure uniform mixing. The prepared mixed solution is ready for use.

[0052] A 30cm layer of Bailey sandstone with a gas-side permeability of 40mD was placed in a core holder. An annular pressure of 10MPa was applied, and the simulated reservoir temperature was 100℃. After evacuation for 4 hours, simulated formation water of 100,000 mg / L was injected into the core, with a measured injection volume of 21.6 mL. The core porosity was 15%. After aging for 2 hours, simulated crude oil of 4 mPa·s was injected into the core at a rate of 0.05 mL / min to establish initial oil saturation. The outlet back pressure was 2.4 MPa. After injecting 2PV of simulated crude oil, 8.4 mL of water was pumped out, resulting in an initial oil saturation of 38.8%. The core was then aged at the reservoir temperature for 48 hours. Water flooding with 100,000 mg / L simulated formation water at an injection rate of 0.1 mL / min for 2PV yielded 2.8 mL of crude oil, resulting in a waterflood recovery rate of 33.1%. Once the produced fluid water cut exceeded 98%, a mixed solvent flooding solution was used, with the injection rate remaining constant at 0.5 PV. This was followed by water flooding until no more oil was produced at the outlet, with a subsequent water flooding injection volume of 1.6 PV. The mixed solvent flooding and subsequent water flooding yielded 3.8 mL of produced crude oil. The mixed solvent flooding after water flooding increased the oil recovery by 45.5%, achieving a total oil recovery of 78.4%.

[0053] Example 4

[0054] This example illustrates a displacement method for significantly improving the recovery rate of low-permeability reservoirs.

[0055] First, prepare a 50,000 mg / L simulated formation water solution using NaCl. Take 350 mL of the simulated formation water solution and place it in a 500 mL stainless steel intermediate container. Add 10 mL of acetone and 120 mL of dimethyl ether to the container from the bottom using a metering pump, and adjust the pressure in the intermediate container to 2.5 MPa from the top. Let it stand at room temperature for more than 48 hours to ensure uniform mixing. The prepared mixed solution is ready for use.

[0056] A 30cm layer of Bailey sandstone with a gas-side permeability of 35mD was placed in a core holder. An annular pressure of 10MPa was applied, and the simulated reservoir temperature was 85℃. After evacuation for 4 hours, 50,000mg / L simulated formation water was injected into the core, with a measured injection volume of 24.8mL. The core porosity was 17%. After aging for 2 hours, simulated crude oil at 6mPa·s was injected into the core at a rate of 0.05mL / min to establish initial oil saturation. The outlet back pressure was 2.4MPa. After injecting 2PV of simulated crude oil, 10.5mL of water was pumped out, resulting in an initial oil saturation of 42.3%. The core was then aged at the reservoir temperature for 48 hours. Water flooding with 50,000mg / L simulated formation water at an injection rate of 0.1mL / min for 2PV yielded 4.4mL of crude oil, achieving a waterflood recovery of 42%. Once the produced fluid water cut exceeded 98%, a mixed solvent flooding was initiated at a constant injection rate of 0.5 PV. This was followed by water flooding until no more oil was produced at the outlet, with a subsequent water flooding injection rate of 2.0 PV. The mixed solvent flooding and subsequent water flooding yielded 2.35 mL of produced crude oil. The mixed solvent flooding after water flooding increased the oil recovery by 22.4%, achieving a total oil recovery of 64.7%.

[0057] Example 5

[0058] This example illustrates a displacement method for significantly improving the recovery rate of low-permeability reservoirs.

[0059] First, prepare a 50,000 mg / L simulated formation water solution using NaCl. Take 350 mL of the simulated formation water solution and place it in a 500 mL stainless steel intermediate container. Add 10 mL of acetone and 120 mL of dimethyl ether to the container from the bottom using a metering pump, and adjust the pressure in the intermediate container to 2.5 MPa from the top. Let it stand at room temperature for more than 48 hours to ensure uniform mixing. The prepared mixed solution is ready for use.

[0060] A 30cm layer of Bailey sandstone with a gas-side permeability of 45mD was placed in a core holder. An annular pressure of 10MPa was applied, and the simulated reservoir temperature was 85℃. After evacuation for 4 hours, 50,000mg / L simulated formation water was injected into the core, with a measured injection volume of 24.8mL. The core porosity was 17%. After aging for 2 hours, simulated crude oil at 6mPa·s was injected into the core at a rate of 0.05mL / min to establish initial oil saturation. The outlet back pressure was 2.4MPa. After injecting 2PV of simulated crude oil, 9.4mL of water was pumped out, resulting in an initial oil saturation of 38%. The core was then aged at the reservoir temperature for 48 hours. Water flooding with 50,000mg / L simulated formation water at an injection rate of 0.1mL / min for 2PV yielded 3.9mL of crude oil, achieving a waterflood recovery rate of 41.5%. Once the produced fluid water cut exceeded 98%, a mixed solvent flooding solution was used, with the injection rate remaining constant at 0.5 PV. This was followed by water flooding until no more oil was produced at the outlet, with a subsequent water flooding injection volume of 2.0 PV. The mixed solvent flooding and subsequent water flooding yielded 2.35 mL of produced crude oil. The mixed solvent flooding after water flooding increased the oil recovery by 25%, achieving a total oil recovery of 66.5%.

[0061] The various embodiments of the present invention have been described above. These descriptions are exemplary and not exhaustive, nor are they limited to the disclosed embodiments. Many modifications and variations will be apparent to those skilled in the art without departing from the scope and spirit of the described embodiments.

Claims

1. A displacement method for substantially improving the recovery of low permeability reservoirs, characterized in that, The displacement method includes: first water flooding, mixed solvent solution flooding, and second water flooding; Mixed solvent solution flooding includes: injecting a mixed solvent solution into a low-permeability reservoir, wherein the mixed solvent solution is a solution containing small molecule compounds; The small molecule compounds are methyl ether and propanol; The amount of propanol used is 7-10 mL, compared to 100-120 mL of dimethyl ether. In the solution of the small molecule compound, the concentration of the small molecule compound is 5-30% v / v; The solvent for the solution of the small molecule compound is water or a salt solution; The injection volume for mixed solvent solution flooding is 0.3-0.6 PV; The conditions that the low-permeability reservoirs meet include: Permeability ≤ 50mD.

2. The displacement method for significantly improving the recovery rate of low-permeability reservoirs according to claim 1, wherein, The saline solution has a mineralization of 3000-300000 mg / L and a concentration of divalent calcium and magnesium ions of 0-5000 mg / L.