Active nanofluid energizing-imbibition fracturing oil displacement method for low-permeability reservoir

Abstract

The invention relates to the technical field of oil and gas field development, in particular to an active nanofluid energizing-imbibition fracturing oil displacement method for a low-permeability reservoir. The method comprises the following steps: determining the half length of a fracture injected by fracturing according to the position of a remaining oil enrichment area from an oil well; first fracturing is conducted, and fracturing fluid injection is controlled to enable a crack to extend to the front edge of the remaining oil enrichment area; injecting formation water into the crack to supplement formation energy, stopping the pump for intermittence after the formation water is injected until the pressure is effectively diffused after the crack is closed; secondary fracturing is carried out, and the cracks extend to completely penetrate through the remaining oil enrichment area; injecting an active nanofluid oil displacement system; stratum water is injected to replace the nanofluid, so that the nanofluid completely enters the remaining oil enrichment area; and stopping the pump and soaking. By means of the method, the active nanofluid oil displacement system can be accurately injected into the remaining oil enrichment area, percolation and efficient oil extraction of the active nanofluid are promoted while stratum energy is supplemented, and the oil production capacity of the low-permeability reservoir oil well is greatly improved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field development, and particularly relates to an active nanofluid energy enhancement - imbibition fracturing oil displacement method for low - permeability reservoirs. Background Technique

[0002] With the in - depth exploration and development of oil and gas in China, low - permeability reservoirs account for an increasingly large proportion in the exploration and development of China's resources. Since the matrix of low - permeability reservoirs mostly has micro - to nano - scale pore throats, the capillary force is significant, and the oil / water / solid interface effect in the confined space is prominent, resulting in large fluid flow resistance, difficult formation energy replenishment, and low recovery efficiency of crude oil in matrix pores. The fracturing oil displacement technology replaces the fracturing fluid with a high - efficiency oil displacement system, fractures low - permeability and remaining - oil - rich well layers, and quickly and efficiently injects a large amount of oil displacement agents into the target layer to improve the recovery rate and supplement the formation energy at the same time. Therefore, the fracturing oil displacement technology has become a good choice for developing low - permeability reservoirs.

[0003] CN109594959A discloses a fracturing oil displacement method for improving the recovery economic efficiency of thin and poor reservoirs in old oilfields. The fracturing oil displacement agent used in this method is a binary composite system of alkali and surfactant. The alkali in the fracturing oil displacement agent is sodium carbonate, the surfactant is petroleum sulfonate, and the water is treated produced water.

[0004] CN115977604B discloses a shale oil nano - imbibition energy - enhancement fracturing method, and the method includes the following steps:

[0005] S1: Under the condition of higher than the fracture pressure, inject the nano - imbibition displacement fracturing fluid with proppant and in - situ gas reaction system into the target low - permeability oil and gas reservoir layer, and shut in the well after fracturing; the addition amount of proppant in the nano - imbibition displacement fracturing fluid accounts for 20 - 30% of the total mass of the fracturing fluid; the in - situ gas reaction system accounts for 10 - 20% of the total volume of the fracturing fluid; S2: When the pressure change of the fracturing well within 24 hours is ≤0.1 MPa for 3 consecutive days, the well can be opened for blowdown.

[0006] Currently, the commonly used fracturing oil displacement agent is an alkali - surfactant binary composite system, and there are several problems in its application to low - permeability reservoirs: (1) It is sensitive to high - temperature, high - pressure, and high - salinity formations, is prone to hydrolysis, is easily affected by the environment, and the application effect is not ideal; (2) It is difficult to enter the micro - and nano - scale pore throats and effectively reach the action area; (3) It is prone to emulsification, causing reservoir damage. In view of the above problems, the present invention proposes to use a temperature - and salt - resistant active nanofluid for fracturing oil displacement. Nanoparticles have the advantages of nano - size, temperature - and pressure - resistance, low cost, easy availability, and environmental friendliness. The nano - type oil displacement agent can effectively enter the fine pores in the low - permeability reservoir and play a role during fracturing oil displacement, significantly improving the recovery effect. Summary of the Invention

[0007] To solve the problems existing in the prior art, the present invention provides an active nanofluid energy enhancement - imbibition fracturing oil displacement method for low - permeability reservoirs. This method creates fractures step by step in batches through fracturing means, and injects formation water and active nanofluid into the high - formation pressure - drop area and the remaining - oil enrichment area in the low - permeability reservoir respectively. The formation water and the active nanofluid reach the target position through filtration, playing the roles of pressure supplementation and energy enhancement and imbibition oil production respectively. The ultra - small particle size and excellent imbibition oil - displacement performance of the active nanofluid can greatly improve the recovery rate of low - permeability reservoirs. At the same time, the formation water supplements the energy deficit in the formation, promoting the efficient oil production of the active nanofluid.

[0008] To achieve the above object, the present invention adopts the following technical solutions:

[0009] The present invention provides an active nanofluid energy enhancement - imbibition fracturing oil displacement method for low - permeability reservoirs, and the method includes the following steps:

[0010] Determine the target layer and location of the remaining - oil enrichment area; determine the fracture half - length of fracturing injection according to the distance between the remaining - oil enrichment area and the oil well.

[0011] Conduct the first fracturing, control the injection of fracturing fluid to make the fracture extend to the front edge of the remaining - oil enrichment area; inject formation water into the fracture to supplement formation energy. After the formation water injection is completed, stop the pump and intermittently wait until the pressure effectively diffuses after the fracture closes; conduct the second fracturing to make the fracture extend to completely pass through the remaining - oil enrichment area; inject the active nanofluid oil displacement system; inject formation water to displace the nanofluid to make it completely enter the remaining - oil enrichment area; stop the pump and soak the well.

[0012] Further, the active nanofluid oil displacement system meets the following conditions:

[0013] (1) The oil / water interfacial tension is 0.1 - 1 mN / m;

[0014] (2) Under the conditions of a temperature of 120 - 150 °C and a salinity of 40000 - 60000 mg / L, the average particle size of the system is not greater than 50 nm;

[0015] (3) Take the natural core of the reservoir for the wettability regulation evaluation experiment, and the oil - phase contact angle is 45 - 60°;

[0016] (4) Conduct the imbibition experiment, and the recovery rate ≥ 25%;

[0017] (5) Conduct the indoor evaluation experiment of matrix - fracture core fracturing oil displacement, and the recovery rate is increased by more than 10%.

[0018] Further, the active nanofluid oil displacement system is composed of the following components and mass percentages: temperature - and salt - resistant nano - active SiDots 0.5% - 1.0%, surfactant FMES 0.1% - 0.2%, and the balance is water.

[0019] Furthermore, the injection volumes of formation water and the active nanofluid flooding system are determined based on the converted value of sand body thickness, the controlled area of the sand body, porosity, and the injected PV value.

[0020] Furthermore, the following method is used to determine the soaking time: the imbibition equilibrium time is calculated from the imbibition and oil displacement experiment of the natural core of the reservoir, and a three-dimensional numerical simulation model of the real formation is established based on the STARS simulator of the CMG software to conduct the simulation of fracturing and oil displacement with the active nanofluid flooding agent. The soaking time is jointly determined by combining the imbibition and simulation results.

[0021] Furthermore, the fracturing fluid used in the primary fracturing is formation water, and the fracturing fluid used in the secondary fracturing is the active nanofluid flooding system. The purpose of injecting formation water is to supplement the energy deficit in the low formation pressure area near the wellbore. After the development of natural energy, the pressure drop curve in the oil well is funnel-shaped, that is, the pressure drop is more obvious closer to the wellbore. Therefore, energy is preferentially supplemented to the formation through the fractures, while avoiding the extension of the active nanofluid flooding system to the oil well side due to the uneven distribution of pressure within the layer during the infiltration in the remaining oil enrichment area, and improving the utilization efficiency of the active nanofluid flooding system. The active nanofluid flooding system has excellent temperature and salt tolerance, high interfacial activity, ultra-small particle size, and high-efficiency imbibition and oil displacement performance. Therefore, it can effectively enter the micro-nano scale pore throats in the low-permeability reservoir for imbibition oil recovery and improve the oil recovery rate.

[0022] Furthermore, the PV value is 0.5 - 0.6.

[0023] Furthermore, the soaking time is 20 - 30 days.

[0024] Compared with the prior art, the present invention has the following advantages:

[0025] Aiming at the problems of serious formation energy deficit, low utilization efficiency of matrix pore remaining oil, and "difficult to inject and produce" in low-permeability reservoirs, the present invention innovatively proposes an active nanofluid energy-enhanced - imbibition fracturing oil displacement method for low-permeability reservoirs. The fracturing oil displacement method of the present invention can accurately inject the active nanofluid flooding system into the remaining oil enrichment area, and while supplementing the formation energy, it promotes the infiltration and efficient oil production of the active nanofluid, greatly improving the oil production capacity of oil wells in low-permeability reservoirs. In addition, the method of the present invention can reduce the operation cost of oil wells, and the economic benefits are obvious. Description of the Drawings

[0026] Figure 1 It is a typical T2 spectrum diagram of the matrix-fracture core fracturing oil displacement experiment process;

[0027] Figure 2 It is the imbibition equilibrium time of the reservoir core;

[0028] Figure 3 Results of optimizing the soaking time for numerical simulation

[0029] Figure 4 Production performance graph of Well X1 Detailed implementation manners

[0030] It should be noted that the following detailed description is exemplary and is intended to provide further illustration of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those of ordinary skill in the technical field to which the present invention belongs.

[0031] It should be noted that the terms used herein are only for describing specific implementation manners and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular forms are also intended to include the plural forms. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they specify the presence of features, steps, operations, and / or combinations thereof.

[0032] In order to enable those skilled in the art to more clearly understand the technical solution of the present invention, the technical solution of the present invention will be described in detail below in conjunction with specific embodiments.

[0033] The preparation method of the nano-active SiDots refers to Patent CN113201321A.

[0034] Example 1

[0035] An energy-enhanced imbibition fracturing oil displacement method using active nanofluids for low-permeability reservoirs, the method comprising the following steps:

[0036] Step 1. Determine the target layer and location of the remaining oil enrichment area;

[0037] Step 2. Determine the fracture half-length of the fracturing injection according to the distance between the remaining oil enrichment area and the oil well;

[0038] Step 3. Conduct the first fracturing, and control the injection of fracturing fluid to make the fracture extend to the front edge of the remaining oil enrichment area. The fracturing fluid is formation water; then inject formation water into the fracture to supplement the formation energy. After the formation water injection is completed, stop the pump and intermittently wait until the pressure effectively diffuses after the fracture closes;

[0039] Step 4. Conduct secondary fracturing to make the fracture extend to completely penetrate the remaining oil enrichment area. The fracturing fluid used in the secondary fracturing is an active nanofluid oil displacement system;

[0040] Step 5. Inject the active nanofluid flooding system; inject formation water to displace the nanofluid so that it completely enters the remaining oil enrichment area; determine the injection volumes of the formation water and the active nanofluid flooding system according to the converted value of the sand body thickness, the sand body controlled area, the porosity, and the injected PV value.

[0041] Step 6. Stop the pump and soak the well. The soaking time is determined by the following method: calculate the imbibition equilibrium time based on the imbibition oil displacement experiment of the reservoir natural core, establish a three-dimensional numerical simulation model of the real formation based on the STARS simulator of the CMG software, conduct the simulation of fracturing oil displacement with the active nanofluid flooding agent, and jointly determine the soaking time by combining the imbibition and simulation results.

[0042] The above-mentioned active nanofluid flooding system satisfies the following conditions:

[0043] (1) The oil / water interfacial tension is 0.1 - 1 mN / m;

[0044] (2) Under the conditions of a temperature of 120 - 150 °C and a salinity of 40000 - 60000 mg / L, the average particle size of the system is not greater than 50 nm;

[0045] (3) Take the reservoir natural core to conduct the wettability regulation evaluation experiment, and the oil phase contact angle is 45 - 60°;

[0046] (4) Conduct the imbibition experiment, and the recovery factor ≥ 25%;

[0047] (5) Conduct the indoor evaluation experiment of matrix-fracture core fracturing oil displacement, and the recovery factor is increased by more than 10%.

[0048] Example 2

[0049] The active nanofluid energy-enhanced imbibition fracturing oil displacement method for low-permeability oil reservoirs is illustrated by taking an oilfield as an example.

[0050] An oilfield is the earliest developed low-permeability large oilfield in China. The Y1 block was discovered with the completion of the exploration well in October 1975 and was developed by elastic test production; after 1988, production capacity was built while rolling, and the annual production capacity reached 12,000 tons in 1998, with the peak daily oil production reaching 52 t / d; in 1996, it was converted to water injection development; after 1999, it entered the decline stage; in 2010, local infill adjustment was implemented in the south, 10 wells were drilled, and Well X1 is an infill oil well in this area. The reservoir depth of this well is 2900 m, the formation temperature is 120 °C, the salinity is 38,000 mg / L, medium porosity (20.7%), low permeability (22.5 mD), low production (liquid production per day < 5 t / d), and low recovery factor (< 10%). After 10 years of water injection development, the formation voidage is 23,000 m³, and the formation pressure drops by 44.05%. It is suitable for the active nanofluid energy-enhanced imbibition fracturing oil displacement method provided by the present invention. The method includes the following steps:

[0051] Step 1: Determine that the target layer of Well X1 is Layer S1. Based on the results of fine reservoir description and the production dynamic data of the oilfield, determine that the target layer for implementing fracturing flooding is Layer S1.

[0052] Step 2: Determine that the total half-length of the fracture is 60 m according to the distance from the farthest boundary of the remaining oil enrichment area in the target layer to Well X1. Among them, the length of the fracture in the energy-enhancing area is 45 m, and the length of the fracture in the remaining oil enrichment area is 15 m.

[0053] Step 3: After indoor core injection experiments and reservoir numerical simulation optimization, determine that the optimal injection PV value is 0.5 - 0.6. For the above oil wells, the average converted thickness of the sand body is 5.34 m, and the average controlled area of the sand body is 6358.5 m 2 and 4945.5 m 2 . The average porosity is 20.7%. Select an injection PV value of 0.5. After calculation, we get:

[0054] The total injection volume of formation water Q1 = 3514 m 3

[0055] The total injection volume of active nanofluid Q2 = 2733 m 3

[0056] According to the injection pressure required at different stages, the injection displacement is determined to be 5 m 3 / min during the fracturing stage and 1.5 m 3 / min during the injection stage.

[0057] Step 4: The active nanofluid flooding system satisfies the following conditions:

[0058] (1) The oil / water interfacial tension is 0.1 - 1 mN / m;

[0059] (2) Under the conditions of a temperature of 120 - 150 °C and a salinity of 40000 - 60000 mg / L, the average particle size of the system is not greater than 50 nm;

[0060] (3) Take the natural core of the reservoir for the wettability control evaluation experiment, and the oil-phase contact angle is 45 - 60°;

[0061] (4) Conduct an imbibition experiment, and the recovery factor ≥ 25%;

[0062] (5) Conduct an indoor evaluation experiment on matrix-fracture core fracturing flooding, and the recovery factor increases by more than 10%.

[0063] First, according to the interfacial tension evaluation experiment, it can be obtained that when the content of nano-active SiDots is 0.5 wt% and the content of surfactant FMES is 0.1 wt%, the oil / water interfacial tension drops to the lowest (0.34 mN / m), and it has good dispersion stability under reservoir temperature and salinity conditions; the wettability evaluation experiment of the reservoir natural core shows that the nano-fluid immersion can transform the oil-wet core slices into water-wet within 48 hours (the oil-phase contact angle changes from 135° to 48°); the imbibition experiment shows that the active nano-fluid can make the imbibition recovery rate of the reservoir core reach more than 35%, with high-efficiency imbibition oil displacement performance; use the indoor core displacement system to conduct a fracturing oil displacement simulation experiment on the fractured reservoir natural low-permeability core, and use the low-field nuclear magnetic method to analyze the remaining oil mobilization effect inside the core. The results show that the overall recovery rate of the core increases by more than 23% after fracturing oil displacement with the active nano-fluid, and the crude oil mobilization effect in small pores (0.01 - 1.00 μm) and large pores (30.00 - 400.00 μm) is obvious.

[0064] From Figure 1 the change of signal amplitude corresponding to different pore diameters in it, it can be seen that during the dynamic imbibition oil displacement process of the core matrix flow unit, the signal amplitudes of small pores and large pores both decrease significantly, indicating that the oil phases in small pores and large pores are effectively mobilized during this process. This is because during the dynamic imbibition oil displacement process, the capillary force in small pores is large, and the wetting phase (water phase) is easy to enter the small pores, displacing the oil phase in the small pores into the medium pores or large pores, reducing the oil content ratio in the small pores; the pore diameter of large pores is large, and the seepage resistance is small. Under the action of the dynamic imbibition displacement pressure difference, the oil phase can also be smoothly discharged, reducing the oil content ratio in the large pores; while for medium pores, due to the capillary force and seepage ability not being dominant, the water phase is not easy to enter and only serves as an oil drainage channel, and the oil content ratio changes little. Therefore, the signal amplitude curve is relatively dense and the change is small. Based on the above results, it is considered that this active nano-fluid system has low oil / water interfacial tension, high-efficiency imbibition oil displacement performance and the ability to change wettability, can effectively mobilize the remaining oil in the micro-nano pore throats of low-permeability reservoirs, and significantly improve the recovery rate. Therefore, this active nano-fluid formula is determined as the fracturing oil displacement agent for the fracturing oil displacement method.

[0065] Step Five: Determine the shut-in time for fracturing oil displacement to be 25 d.

[0066] First, according to the observation of the imbibition results of the reservoir natural low-permeability core, it is found that the recovery rate growth of the active nano-fluid gradually slows down after 25 d ( Figure 2 ). Use the STARS simulator of CMG software to establish a three-dimensional numerical simulation model of the real formation, and conduct a simulation of fracturing oil displacement with the active nano-fluid. The results show that there is a maximum value of the recovery rate when the shut-in time is within 20 - 30 d ( Figure 3 ). Therefore, the shut-in time for the fracturing oil displacement method is determined to be 25 d.

[0067] Step 6: First, control the injection pressure to extend the fracture to 45 m, and continuously inject 3514 m into the fracture 3 formation water to supplement the formation energy. After the injection is completed, stop the pump and intermittently wait until the fracture closure pressure effectively diffuses; then refracture to extend the fracture to 60 m and inject 2733 m 3 of active nanofluid, and finally inject 30 m 3 formation water to displace the active nanofluid so that it completely enters the remaining oil enrichment area.

[0068] Table 1 Plugging and Pumping Construction Procedure

[0069]

[0070]

[0071] Step 7: After well X1 is shut in for 25 days and then opened, it is found that the water absorption capacity of the reservoir has increased because the active nanofluid makes the wettability of the reservoir more hydrophilic; the production dynamics before and after fracturing and oil displacement of well X1 are as Figure 4 shown. It is measured that both the daily liquid production and the daily oil production of this well have increased, and the decline of oil production has been effectively alleviated. So far, the oil increment is nearly 300 tons and it is continuously effective (for more than 1 year).

[0072] The above embodiments are preferred embodiments of the present invention, but the embodiments of the present invention are not limited to the above embodiments. Any other changes, modifications, substitutions, combinations, and simplifications made without departing from the spirit and principle of the present invention shall be equivalent replacement methods and are all included in the protection scope of the present invention.

Claims

1. An energy - enhancing and imbibition - fracturing oil displacement method using active nanofluids for low - permeability reservoirs, characterized in that, It includes the following steps: Determine the target layer and location of the remaining oil enrichment area; determine the fracture half-length of the fracturing injection according to the distance between the remaining oil enrichment area and the oil well location; Conduct the first fracturing, and control the injection of fracturing fluid to make the fracture extend to the front edge of the remaining oil enrichment area; inject formation water into the fracture to supplement the formation energy. After the formation water injection is completed, stop the pump and intermittently shut in until the pressure effectively diffuses after the fracture closes. Conduct the second fracturing to make the fracture extend to completely penetrate the remaining oil enrichment area; inject the active nanofluid oil displacement system; inject formation water to displace the nanofluid to make it completely enter the remaining oil enrichment area; stop the pump and soak the well.

2. The method according to claim 1, characterized in that, The active nanofluid oil displacement system meets the following conditions: (1) The oil / water interfacial tension is 0.1 - 1 mN / m; (2) Under the conditions of a temperature of 120 - 150 °C and a salinity of 40000 - 60000 mg / L, the average particle size of the system is not greater than 50 nm; (3) Take the natural core of the reservoir to conduct a wettability control evaluation experiment, and the oil phase contact angle is 45 - 60°; (4) Conduct an imbibition experiment, and the recovery rate ≥ 25%; (5) Conduct an indoor evaluation experiment on matrix-fracture core fracturing oil displacement, and the recovery rate is increased by more than 10%.

3. The method according to claim 2, characterized in that, The active nanofluid oil displacement system consists of the following components and mass percentages: 0.5% - 1.0% of temperature- and salt-resistant nanoactive SiDots, 0.1% - 0.2% of surfactant FMES, and the balance is water.

4. The method according to claim 1, characterized in that, Determine the injection volumes of formation water and the active nanofluid oil displacement system according to the converted value of the sand body thickness, the sand body control area, the porosity, and the injection PV value.

5. The method according to claim 1, characterized in that, Use the following method to determine the soaking time of the well: Calculate the imbibition equilibrium time according to the imbibition oil displacement experiment of the natural core of the reservoir, and establish a three-dimensional numerical simulation model of the real formation based on the STARS simulator of the CMG software. Conduct a simulation of fracturing oil displacement with the active nanofluid oil displacement agent, and jointly determine the soaking time of the well by combining the imbibition and simulation results.

6. The method according to claim 1, characterized in that, The fracturing fluid used for the primary fracturing is formation water, and the fracturing fluid used for the secondary fracturing is the active nanofluid oil displacement system.

7. The method according to claim 4, characterized in that, The PV value is 0.5 - 0.

6.

8. The method according to claim 5, characterized in that, The soaking time of the well is 20 - 30 days.

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