A method for nitrogen foam flooding of a fractured shale oil reservoir

Abstract

The present application belongs to the field of oil and gas field development, and particularly relates to a nitrogen foam flooding method for fractured shale oil reservoirs; it solves the problems of long production cycle and difficult matrix production of current foam flooding technology; the technical scheme is: through physical simulation experiment, reservoir core, crude oil and formation water are obtained; first, wettability reversal experiment is carried out to determine the optimal effective time of wettability reversal agent, and imbibition experiment is carried out to determine the optimal well shut-in time; after establishing the initial oil saturation of the core, formation water flooding and foam flooding experiments are carried out in turn; cumulative oil production is recorded and oil displacement efficiency is calculated; finally, staged foam flooding experiment is carried out, and oil displacement efficiency is also calculated; after the experiment, the curves of oil displacement efficiency and time change of staged foam flooding, foam flooding and formation water flooding are compared and analyzed; the results show that the final oil displacement efficiency of staged foam flooding is the highest; the new method can significantly shorten the production lag period and improve the final oil displacement efficiency.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development, and specifically relates to a nitrogen foam flooding method for fractured shale oil reservoirs. Background Technology

[0002] Foam flooding addresses the challenges of fractured reservoirs by injecting gases (such as nitrogen and carbon dioxide) and surfactant solutions to generate stable foam within the reservoir. Traditional conventional foam flooding techniques suffer from a long "lag period," meaning that in the early stages of oil displacement, conventional foam flooding efficiency is significantly lower than water flooding. Furthermore, factors such as rock wettability prevent the matrix pores from fully absorbing the foaming agent for foaming and oil displacement. In fractured shale reservoirs, due to the presence of natural or artificial fracture networks, water flooding or conventional foam flooding is prone to "channeling," making it difficult for the displacement medium to effectively enter the matrix pores, resulting in low oil displacement efficiency. Especially in high-permeability fracture channels, gas or foam preferentially passes through the fractures, failing to effectively mobilize crude oil from the matrix. Therefore, a method that can seal fractures while simultaneously activating crude oil mobilization within the matrix pores is urgently needed. In this invention, by cleverly pre-treating the core with chemical agents and controlling the injection timing, the problem of low initial efficiency and difficulty in matrix utilization caused by foam "flowing" in fractures is directly solved, and its later advantages are amplified. This not only significantly improves the early oil displacement efficiency, but also increases the final recovery rate, achieving an overall improvement in efficiency. This further improves the economics of foam flooding technology in fractured shale reservoirs and has clear practical applications. Summary of the Invention

[0003] The objective of this invention is to obtain core samples from shale oil reservoirs through physical simulation experiments, prepare experimental materials, conduct wetting reversal experiments to determine the optimal activation time of the wetting reversal agent, conduct percolation experiments to determine the optimal well-closing time, establish the initial oil saturation of the core samples using shale oil reservoir crude oil and formation water, conduct formation water flooding and foam flooding experiments, calculate the oil displacement efficiency, and then conduct staged foam flooding experiments to calculate the oil displacement efficiency. After the experiments, based on the experimental data, curves showing the change in oil displacement efficiency over time for staged foam flooding, foam flooding, and formation water flooding are established, and the final oil displacement efficiency of the three is compared. Staged foam flooding has the highest final oil displacement efficiency. This invention's novel method, through the synergistic effect of wetting reversal, well-closing percolation, and foam flooding, significantly shortens the production lag period and improves the final oil displacement efficiency compared to foam flooding and formation water flooding.

[0004] This invention is applicable to fractured shale reservoirs. By using pre-wetting reversal and well-sealing percolation operations, it significantly enhances the sealing ability of foam in fractures and the foaming efficiency in the matrix, effectively overcoming the problems of "gas channeling" and "liquid channeling" that easily occur in fractured reservoirs. It realizes the synergistic utilization of fractures and matrix, thus exhibiting a better oil displacement effect in fractured shale reservoirs.

[0005] To achieve the above objectives, the present invention provides a nitrogen foam flooding method for fractured shale oil reservoirs, the method comprising the following steps:

[0006] The first step is to collect core samples from shale oil reservoirs, process the core samples by cutting them into cylindrical shapes, and manually split and fracture the processed core samples to measure their length, diameter, and porosity.

[0007] The second step is to prepare experimental materials, obtain formation water from the shale oil reservoir on site, use formation water and cocamidopropyl betaine as the wetting reversal agent, use sodium dodecyl sulfate as the surfactant, use hydrolyzed polyacrylamide as the foam stabilizer, use crude oil from the shale oil reservoir as the experimental oil, and use industrial nitrogen as the displacement gas.

[0008] The third step involved preparing a wetting reversal agent with a mass fraction of 0.15% cocamidopropyl betaine, conducting a wetting reversal experiment, modifying the core to be hydrophilic, and determining that the optimal effective time of the wetting reversal agent was 15 minutes.

[0009] The fourth step is to conduct a permeation test. The surfactant sodium dodecyl sulfate and the foam stabilizer hydrolyzed polyacrylamide are prepared into a foaming agent solution at a concentration ratio of 2:1. The core is then placed into the prepared foaming agent solution for permeation, and the optimal well-clogging time is determined to be 30 minutes.

[0010] The fifth step involves using crude oil and formation water from the shale oil reservoir and employing an oil-water flooding experiment. First, the core is saturated with crude oil, and then formation water is used to flood the oil, thus obtaining the initial oil saturation of the core.

[0011] Step 6: Under reservoir temperature and pressure conditions, conduct formation waterflooding experiments, recording the cumulative oil production every 60 minutes to calculate the oil displacement efficiency. Prepare a foaming agent using sodium dodecyl sulfate and hydrolyzed polyacrylamide at a concentration ratio of 2:1, mix it with nitrogen at a gas-liquid volume ratio of 4:1 to form foam, and continuously displace the core sample. Record the cumulative oil production every 60 minutes to calculate the oil displacement efficiency. The formula for calculating the oil displacement efficiency is:

[0012] ,

[0013] In the formula, P e Oil displacement efficiency, expressed in % %. Vo Cumulative oil production, in mL; L This refers to the core length, in cm. D This refers to the core diameter, in cm. S oi The initial oil saturation of the core is expressed in % (%). m The core porosity was measured. After the experiment, the core was washed and resaturated with oil for foam flooding experiments.

[0014] Step 7: Under reservoir temperature and pressure, conduct a staged foam flooding experiment. Before the experiment, treat the core with a wetting reversal agent for 15 minutes, then place the core into the core holder, inject the foaming agent solution into the core, shut the well for 30 minutes after injection, and finally start injecting nitrogen gas to form foam at a gas-liquid volume ratio of 4:1 to continuously displace the core for 30 minutes. Record the cumulative oil production once, and then continue to displace the core. Record the cumulative oil production every 60 minutes to calculate the oil displacement efficiency.

[0015] Step 8: Based on the experimental data, plot the oil displacement efficiency curves of staged foam flooding, foam flooding, and formation water flooding as a function of time. As time increases, the oil displacement efficiency of the three types increases, but the upward trend slows down. Comparing the time of the intersection of the staged foam flooding and formation water flooding curves, the intersection time of the former is significantly earlier than that of the latter, shortening the production lag period. Comparing the final oil displacement efficiency of the three types, the final oil displacement efficiency of staged foam flooding is the highest.

[0016] Compared with the prior art, the present invention has the following beneficial effects: (1) It solves the difficulties in foam flooding of fractured shale reservoirs and significantly improves the oil displacement efficiency; (2) It greatly shortens the production cycle and improves the efficiency of the whole process; (3) It reduces development costs and improves economic benefits; (4) This method is designed for the geological characteristics of fractured shale reservoirs. Through the synergistic effect of wetting reversal and well-sealing permeation, it significantly improves the sealing ability of foam in fractures and the oil displacement efficiency in the matrix, and has obvious reservoir adaptability advantages. Attached Figure Description

[0017] In the attached diagram:

[0018] Figure 1 This is the overall technical roadmap for this method.

[0019] Figure 2 It is a graph showing the relationship between the wetting angle and time.

[0020] Figure 3 It is a graph showing the cumulative oil production as a function of well shut-in time.

[0021] Figure 4It is a graph showing the relationship between oil displacement efficiency and time. Detailed Implementation

[0022] The present invention will be further described below with reference to the embodiments and accompanying drawings;

[0023] This invention provides a nitrogen foam flooding method for fractured shale oil reservoirs. Figure 1 As the overall technical roadmap of this method, it includes the following steps:

[0024] First, core samples are collected from shale oil reservoirs, processed manually, and then the length, diameter, and porosity of the core samples are measured.

[0025] In this embodiment, the core samples collected from the shale oil reservoir are first cut into cylindrical shapes, and then the cut core samples are split to create fractures. The length of the core samples is then measured. L It is 4.94cm in length and has a diameter of 1.5mm. D The porosity is 2.41 cm. m The calculated pore volume of the core, based on a pore size of 16.75%, is 2.072 cm³. 3 ;

[0026] Second, prepare experimental materials, obtain shale oil reservoir formation water on site, wetting reversal agent is prepared by formation water and cocamidopropyl betaine, surfactant is sodium dodecyl sulfate, foam stabilizer is hydrolyzed polyacrylamide, experimental oil is crude oil from shale oil reservoir, and displacement gas is industrial nitrogen.

[0027] In this embodiment, formation water from the shale oil reservoir was obtained from the field, with a total salinity of 60437.45 mg / L. The wetting reversal agent was prepared by mixing formation water and cocamidopropyl betaine to form a solvent with a mass fraction of 0.15%. The main chemical component of the foaming agent was sodium dodecyl sulfate surfactant with a mass fraction of 0.6%, and the foam stabilizer was hydrolyzed polyacrylamide with a mass fraction of 0.3%, with a mixing ratio of 2:1. The experimental oil was crude oil from the shale oil reservoir, with a density of 845.5 kg / m³ at 50°C. 3 The viscosity is 14.7 mPa·s, and the industrial nitrogen used as the displacement gas has a purity of 99.99%.

[0028] Third, wetting reversal experiments were conducted to modify the core to be hydrophilic and determine the optimal effective time of the wetting reversal agent.

[0029] In this embodiment, a wetting reversal agent with a mass fraction of 0.15% was prepared using formation water and cocamidopropyl betaine. A wetting reversal experiment was conducted, with the core sample treated with the wetting reversal agent for 30 minutes. The wetting angle was measured every 3 minutes. Based on the experimental data, a curve showing the change in wetting angle over time was established, such as... Figure 2As shown in the curve, the wetting angle decreases with increasing time, the hydrophilicity increases, and the wetting angle tends to stabilize and remain unchanged after 15 min of wetting time. That is, the optimal effective time of the wetting reversal agent is 15 min.

[0030] Fourth, conduct permeation experiments. Prepare a foaming agent solution by mixing sodium dodecyl sulfate, a surfactant, and hydrolyzed polyacrylamide, a foam stabilizer, at a concentration ratio of 2:1. Place the core sample into the prepared foaming agent solution to seal the well and determine the optimal sealing time.

[0031] In this embodiment, the surfactant sodium dodecyl sulfate and the foam stabilizer hydrolyzed polyacrylamide were prepared into solutions with a mass fraction of 0.6% and 0.3% respectively, in a ratio of 2:1. The core sample was then placed in these solutions for well sealing, and the cumulative oil production was recorded every 5 minutes. A curve showing the cumulative oil production over time was established based on the experimental data. Figure 3 As shown, the cumulative oil production increases with time, then plateaus after 30 minutes and stops changing. The optimal well shut-in time is determined to be 30 minutes.

[0032] Fifth, using the oil-water flooding experimental method, the core was saturated with crude oil, and then formation water was used for oil flooding to obtain the initial oil saturation of the core.

[0033] In this embodiment, the experimental oil is crude oil from a shale oil reservoir, and the displacement water is formation water. The core is 100% saturated with formation water, and then the core is loaded into a core holder and injected with crude oil from the shale oil reservoir. When only oil is produced at the outlet and no water is produced, the water is bound. Then, formation water flooding is carried out. The core is loaded into a core holder and formation water is injected to flood the oil. The oil is continuously flooded until the initial oil saturation of the core is reached and then the oil flooding is stopped.

[0034] Sixth, conduct formation water flooding experiments, record the cumulative oil production, and calculate the oil displacement efficiency; conduct foam flooding experiments, record the cumulative oil production, and calculate the oil displacement efficiency.

[0035] In this embodiment, all experiments were conducted at a reservoir temperature of 50°C and a reservoir pressure of 30 MPa. Formation waterflooding was performed, and the cumulative oil production was recorded every 60 minutes to calculate the displacement efficiency. The pressure gradient was then increased, and the displacement was repeated multiple times. After the experiment, the core was washed clean and resaturated with oil for foam flooding. Nitrogen and foaming agent solution were mixed in a 4:1 ratio to form foam for continuous displacement, and the cumulative oil production was recorded every 60 minutes to calculate the displacement efficiency. The pressure gradient was then increased, maintaining the same pressure gradient at each stage of the displacement process as the formation waterflooding pressure gradient, and the displacement was repeated multiple times. The formula for calculating the displacement efficiency is:

[0036] ,

[0037] In the formula,P e Oil displacement efficiency, expressed in % %. V o Cumulative oil production, in mL; L Core length, in cm: D This refers to the core diameter, in cm. S oi The initial oil saturation of the core is expressed in % (%). m Core porosity;

[0038] Seventh, conduct phased foam flooding experiments, record the cumulative oil production, and calculate the flooding efficiency;

[0039] In this embodiment, the experiment was conducted at a reservoir temperature of 50°C and a reservoir pressure of 30 MPa. Before the experiment, the core was treated with a wetting reversal agent for 15 minutes to allow sufficient time for the wetting reversal agent to fully modify the fracture walls and matrix surface of the core to be hydrophilic, ensuring that the subsequent frother solution could fully penetrate the matrix pores. Then, the core was loaded into the core holder, and the frother solution was injected into the core. After injection, the well was shut off for 30 minutes to allow sufficient time for the frother solution to fully penetrate and enrich the matrix pores. Finally, nitrogen gas was injected to create a gas-liquid mixture. A foam was formed at a ratio of 4:1 and continuously displaced the core for 30 minutes. Nitrogen gas was allowed to come into contact with the foaming agent solution in the fractures to generate foam that sealed the fractures. Under pressure differential, nitrogen gas entered the matrix pores and reacted with the foaming agent solution enriched in the matrix to generate foam in situ, driving the crude oil in the matrix pores. The cumulative oil production was recorded once. Then, foam displacement of the core was continued, and the cumulative oil production was recorded every 60 minutes to calculate the oil displacement efficiency. Then, the pressure gradient was increased to keep the pressure gradient at each stage the same as the formation water flooding pressure gradient, and the displacement was repeated multiple times.

[0040] Eighth, based on the experimental data, plot the curves of the oil displacement efficiency of the three stages of foam flooding, foam flooding and formation water flooding as a function of time.

[0041] In this embodiment, the curves showing the change in oil displacement efficiency over time for staged foam flooding, foam flooding, and formation water flooding are compared, as follows: Figure 4 As shown, the oil displacement efficiency of the three methods increases with time, but the upward trend slows down. Comparing the time of the intersection of the staged foam flooding and formation water flooding curves, the intersection time of the former is significantly earlier than that of the latter, which shortens the production lag period. Comparing the final oil displacement efficiency of the three methods, the final oil displacement efficiency of staged foam flooding is the highest, reaching 30.41%.

[0042] This manual comprehensively compares three schemes—formation water flooding, foam flooding, and staged foam flooding—through rigorous physical simulation experiments. All experiments were conducted under simulated fractured shale reservoir conditions using artificially fractured core samples. Compared to foam flooding and formation water flooding, the staged foam flooding scheme demonstrated the best performance and the highest final oil displacement efficiency. It also showed the fastest results; the intersection time of the efficiency curves for staged foam flooding and formation water flooding was significantly earlier, greatly shortening the production lag period and allowing economic benefits to materialize sooner. It is suitable for fractured shale reservoirs, effectively overcoming the problems of fracture channeling and matrix mobilization difficulties through a three-step synergy of "wetting reversal - well-sealing percolation - foam flooding." The comparative results clearly demonstrate that the staged foam flooding scheme has the best overall performance and is particularly suitable for addressing the pain points of foam flooding in fractured shale reservoirs.

[0043] Compared with the prior art, the present invention has the following beneficial effects: (1) It solves the difficulties in foam flooding of fractured shale reservoirs and significantly improves the oil displacement efficiency; (2) It greatly shortens the production cycle and improves the efficiency of the whole process; (3) It reduces development costs and improves economic benefits; (4) This method is designed for the geological characteristics of fractured shale reservoirs. Through the synergistic effect of wetting reversal and well-sealing permeation, it significantly improves the sealing ability of foam in fractures and the oil displacement efficiency in the matrix, and has obvious reservoir adaptability advantages.

[0044] Finally, it should be noted that the above embodiments are only used to illustrate and not limit the technical solutions of the present invention. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that modifications or equivalent substitutions can still be made to the present invention without departing from the spirit and scope of the present invention. Any modifications or partial substitutions should be covered within the scope of the claims of the present invention.

Claims

1. A method for nitrogen foam flooding of a fractured shale oil reservoir, characterized by, Includes the following steps; S001, core samples were collected from shale oil reservoirs, processed, and cut into cylindrical shapes. The processed core samples were then split and fractured using artificial methods. The length, diameter, and porosity of the core samples were measured. S002, Prepare experimental materials, obtain shale oil reservoir formation water on site, the wetting reversal agent is prepared by formation water and cocamidopropyl betaine, the surfactant is sodium dodecyl sulfate, the foam stabilizer is hydrolyzed polyacrylamide, the experimental oil is crude oil from shale oil reservoir, and the displacement gas is industrial nitrogen. S003, a wetting reversal agent with a mass fraction of 0.15% cocamidopropyl betaine was prepared and a wetting reversal experiment was conducted to modify the core to be hydrophilic. The optimal effective time of the wetting reversal agent was determined to be 15 min. S004, an infiltration experiment was conducted. The surfactant sodium dodecyl sulfate and the foam stabilizer hydrolyzed polyacrylamide were prepared into a foaming agent solution at a concentration ratio of 2:

1. The core was then placed into the prepared foaming agent solution for infiltration, and the optimal well-clogging time was determined to be 30 minutes. S005 uses crude oil and formation water from shale oil reservoirs and employs the oil-water flooding experimental method. First, the core is saturated with crude oil, and then formation water is used for oil flooding to obtain the initial oil saturation of the core. In S006, under reservoir temperature and pressure conditions, a formation waterflooding experiment was conducted. The cumulative oil production was recorded every 60 minutes to calculate the oil displacement efficiency. A foaming agent was prepared by mixing sodium dodecyl sulfate and hydrolyzed polyacrylamide at a concentration ratio of 2:1, and then mixed with nitrogen at a gas-liquid volume ratio of 4:1 to form foam. This foam continuously displaced the core sample, and the cumulative oil production was recorded every 60 minutes to calculate the oil displacement efficiency. The formula for calculating the oil displacement efficiency is as follows: ， wherein, P e Oil displacement efficiency, %; V o Cumulative oil production, mL; L Core length, cm; D Core diameter, cm; S oi Initial oil saturation of core, %; m Porosity of core; after the experiment, the core was washed and resaturated with oil for foam oil displacement experiment; S007, under reservoir temperature and pressure, a staged foam flooding experiment was carried out. Before the experiment, the core was treated with a wetting reversal agent for 15 minutes. Then, the core was placed in the core holder and the foaming agent solution was injected into the core. After the injection was completed, the well was shut off for 30 minutes. Finally, nitrogen was injected to form foam with a gas-liquid volume ratio of 4:1 to continuously displace the core for 30 minutes. The cumulative oil production was recorded once. After that, the core was displaced again and the cumulative oil production was recorded every 60 minutes. The oil displacement efficiency was calculated. S008. Based on experimental data, curves showing the changes in oil displacement efficiency over time for staged foam flooding, foam flooding, and formation water flooding were plotted. As time increased, the oil displacement efficiency of the three methods increased, and the upward trend slowed down. Comparing the time of the intersection of the staged foam flooding and formation water flooding curves, the intersection time of the former was significantly earlier than that of the latter, shortening the production lag period. Comparing the final oil displacement efficiency of the three methods, the final oil displacement efficiency of staged foam flooding was the highest.

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