Crude oil production scale evaluation method for water-gas alternate injection of unconventional sandstone reservoir

Abstract

The invention discloses a crude oil production scale evaluation method for unconventional sandstone reservoir water and gas alternate injection, and relates to the technical field of oil and gas development experiments. The method comprises the following steps: scanning a rock core sample by using computer section CT scanning equipment to obtain movable fluid pore throat scale characteristics of the rock core sample; performing saturated water and saturated oil experiments on the core sample to obtain an original stratum oil-water distribution model of the core sample; sequentially carrying out a water flooding experiment and a gas flooding experiment on the rock core sample, and carrying out transverse relaxation time T2 spectrum sampling on the rock core sample by using nuclear magnetic resonance equipment to obtain a T2 spectrum of a water flooding stage, a T2 spectrum area value of a gas flooding stage and a T2 spectrum of the gas flooding stage; determining a relational expression between the crude oil production scale and the T2 spectrum; and respectively substituting the initial value and the cutoff value of the T2 spectrum in the water flooding stage and the gas flooding stage into a relational expression between the crude oil production scale and the T2 spectrum to obtain the crude oil production scale in the water flooding stage and the gas flooding stage. The method can optimize confirmation of the pore throat scale.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas development experiments, and in particular to a method for evaluating crude oil production scale in an unconventional sandstone reservoir with alternating water and gas injection. Technical Background Unconventional tight sandstone reservoirs possess diverse and highly heterogeneous pore structures, with extremely widespread pore throat distribution and the presence of complex features such as micro- and nano-scale pore throats and microfractures, which profoundly influence fluid flow and interactions. Capillary forces, hysteresis, and multiphase flow compete at extremely small scales, making them difficult to capture using traditional macroscopic parameters. Conventional flooding methods struggle to fully characterize fluid phase changes and interfacial evolution during alternating water-gas flooding.

[0002] Currently, commonly used technologies such as scanning electron microscopy, cast thin sections, and high-pressure mercury injection can reveal some dynamic production information, but they are limited by spatial resolution and dynamic response time, making it difficult to achieve continuous and high-precision characterization of crude oil production scales. Summary of the Invention

[0003] Based on this, the present invention provides a method for evaluating the scale of crude oil production during alternating water and gas injection in unconventional sandstone reservoirs. This method can optimize the determination of the pore throat scale of movable fluids during oil displacement in unconventional sandstone reservoirs.

[0004] The present invention adopts the following technical solutions: The present invention provides a method for evaluating the scale of crude oil production in an unconventional sandstone reservoir with alternating water and gas injection, comprising: Prepare core samples of unconventional sandstone standard plugs and scan them using computerized cross-sectional CT scanning equipment to obtain the movable fluid pore throat scale characteristics of the core samples; Water-saturated and oil-saturated experiments were conducted on the core samples. A mixed solution of actual formation water and manganese water, and a simulated oil sample were sequentially displaced deep into the core of the core sample using a high-pressure, high-precision plunger pump. Displacement was stopped when the liquid content of the output fluid at the core sample outlet reached a preset threshold, resulting in a model of the original formation oil and water distribution of the core sample. A water flooding experiment was conducted on the core sample. When the liquid content of the output fluid at the outlet reached the preset threshold during the water flooding experiment, the flooding was stopped and the transverse relaxation time of the core sample was measured using a nuclear magnetic resonance device. T 2 spectrum sampling to obtain the water flooding stage T 2 scores; A gas drive experiment was conducted on the core sample. When the mass of the output fluid at the outlet did not change during the gas drive experiment, the displacement was stopped and the transverse relaxation time of the core sample was measured using a nuclear magnetic resonance device. T 2 spectrum sampling, obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 scores; The movable fluid pore throat size characteristics of the core samples were compared with those of the gas flooding stage. T 2 spectrum area values ​​to determine the crude oil production scale and T The limit of the difference between the two spectra is equal to zero. The crude oil production scale and T 2 spectra to interpolate and correlate to determine the scale and T 2. The relationship between the spectra; The water flooding stage T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T The relationship between the two spectra is used to obtain the crude oil production scale in the water drive stage, and the crude oil production scale in the gas drive stage is obtained. T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T 2 spectra, and obtain the crude oil production scale in the gas drive stage.

[0005] Preferably, the crude oil production scale is T The process of constructing the relationship between the 2 spectra specifically includes: When the core sample is saturated with a single-phase fluid, the preliminary expression for the relaxation rate of the fluid is expressed as: ; in, is the relaxation rate of the fluid, represents the relaxation time, represents the transverse surface relaxation strength, represents the pore surface area, represents the pore volume, represents the diffusion coefficient, represents the magnetic gyrometry ratio, represents the echo interval, represents the magnetic field gradient, represents the transverse bulk relaxation time; Ignore the diffusion relaxation term of the actual fluid , volume relaxation term , the relaxation rate of a single-phase fluid in a uniform magnetic field is determined as: ; According to the pore radius being equal to the product of the movable fluid pore throat radius and the pore throat ratio, T 2 There is a significant power exponential relationship between relaxation time and crude oil production scale, which can be determined T The preliminary expression of 2 spectrum is: ; in, r Represents the scale of crude oil mobilization, n is the power index, F trepresents the average pore-throat ratio of rock pores, F s represents the pore shape factor; right T 2 spectrum is solved, and the expression of crude oil utilization scale is obtained as follows: ; Define the expression of crude oil production scale , then determine the crude oil production scale and T The preliminary relationship between the two spectra is: ; draw T 2 spectrum and the cumulative distribution curve of crude oil production scale, and select the production scale and transverse relaxation time for interpolation correlation, and solve the parameters in the relationship by the least squares method C and n ; The formula corresponding to the least squares method is: ; The least squares method is used to obtain C and n Substitute the crude oil utilization scale and T The preliminary relationship between the two spectra is used to obtain the crude oil production scale and T 2 The relationship between the spectra.

[0006] Preferably, determine the scale of crude oil production and T The solution set where the limit of the difference between the two spectra is equal to zero includes: Obtain crude oil utilization scale and T The limit of the difference between two spectra is: ; in, is the pore throat scale characteristic of the movable fluid in the core sample, i is the frequency, x is the frequency value point, For the displacement stage T 2 spectral curves, is the minimum relaxation time, is the maximum value of relaxation time; The found movable fluid pore throat size and T 2 The limit value of the spectrum integral is determined as the crude oil production scale and T 2 The solution set of the spectrum.

[0007] Preferably, the crude oil production scale and T The number of solution sets of the 2-spectrum ranges from a first preset value to a second preset value and is uniformly distributed.

[0008] Preferably, the process for preparing the core sample of the unconventional sandstone standard plunger specifically includes: Screen, classify and number the selected unconventional sandstone cores to determine the test cores; The test cores were cleaned continuously for 10 days using benzene and petroleum ether in a ratio of 3:1 at 5 MPa and 80°C; The cleaned test core was placed in an 80°C constant temperature box for 24 hours for drying; After drying, the test core is cut and polished to produce core samples of unconventional sandstone standard plungers with a preset length and a preset diameter.

[0009] Preferably, the core samples include core samples No. 1, No. 2, and No. 3; and a water saturation test is performed on the core samples, specifically including: The mixed solution of actual formation water and manganese water was driven into the core depth at a temperature of 70°C, a displacement rate of 0.10 mL / min, and a displacement pressure of 15 MPa; When the liquid content of the outlet output fluid reaches 10PV during the displacement process, the displacement is stopped and the original formation water distribution model of the core sample is obtained.

[0010] Preferably, the unconventional sandstone standard plug core samples include core samples No. 1, No. 2, and No. 3; and an oil saturation test is performed on the core samples, specifically including: After simulating the original formation water distribution, the simulated oil sample was displaced to the core depth at a temperature of 70°C, a displacement rate of 0.10 mL / min, and a displacement pressure of 18 MPa; When the liquid content of the output fluid at the outlet reaches 10PV during the displacement process, the displacement is stopped; Nuclear magnetic resonance on core samples T 2 spectrum sampling to establish the original formation oil and water distribution model of the core sample.

[0011] Preferably, the core samples include core samples No. 1, No. 2 and No. 3; a water flooding experiment is conducted on the unconventional sandstone core samples for establishing the original formation oil-water distribution model to obtain the water flooding stage. T 2 Spectrum area value and water flooding stage T 2 spectrum, specifically including: The actual formation water was displaced to the deep core at a temperature of 70°C and a displacement rate of 0.10 mL / min; The displacement pressures of core samples No. 1, No. 2, and No. 3 were set to 8 MPa, 15 MPa, and 22 MPa, respectively. The confining pressure pump was used to set the confining pressures of core samples No. 1, No. 2, and No. 3 to 10 MPa, 17 MPa, and 24 MPa, respectively. When the water content of the output fluid from outlets 1, 2, and 3 of core samples is above 98%, the displacement is stopped; Conduct water flooding experiments using NMR T 2 spectrum sampling, to obtain the water flooding stage T 2 Spectrum area value and water flooding stage T 2 scores.

[0012] Preferably, the core samples include core samples No. 1, No. 2 and No. 3; a gas drive experiment is performed on the core samples to obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 spectrum, specifically including: The temperature was set to a constant 70°C and the displacement rate to 0.10 mL / min; The CO2 injection pressures of core samples 1, 2, and 3 were set to 8 MPa, 15 MPa, and 22 MPa, respectively, using a high-pressure, high-precision plunger pump. The confining pressures of core samples 1, 2, and 3 were set to 10 MPa, 17 MPa, and 24 MPa, respectively, using a confining pressure pump. Physical flow simulation experiments of CO2 flooding were conducted on core samples 1, 2, and 3, with CO2 in supercritical, near-miscible, and miscible states, respectively. Displacement was stopped at each stage when the quality of the output fluid at the outlet no longer changed. Nuclear magnetic resonance after multiphase CO2 flooding T 2 spectrum sampling, to obtain the gas drive stage T 2 Spectral area value and NMR of gas flooding stage T 2 scores.

[0013] The present invention provides a crude oil production scale evaluation device for alternate water and gas injection in unconventional sandstone reservoirs, comprising: The acquisition module is used to prepare core samples of unconventional sandstone standard plugs and scan the core samples using a computerized cross-section (CT) scanner to obtain the movable fluid pore throat scale characteristics of the core samples; A module was established to conduct water-saturated and oil-saturated experiments on core samples. A mixed solution of actual formation water and manganese water, followed by a simulated oil sample, was sequentially displaced deep into the core of the core sample using a high-pressure, high-precision plunger pump. Displacement was stopped when the liquid content of the output fluid at the core sample outlet reached a preset threshold, resulting in a model of the original formation oil and water distribution in the core sample. The water flooding module is used to conduct water flooding experiments on core samples. When the liquid content of the output fluid at the outlet reaches the preset threshold during the water flooding experiment, the flooding is stopped and the transverse relaxation time of the core sample is measured using nuclear magnetic resonance equipment. T 2 spectrum sampling to obtain the water flooding stage T 2 scores; The gas drive module is used to conduct gas drive experiments on core samples. When the quality of the output fluid at the outlet no longer changes during the gas drive experiment, the displacement is stopped and the transverse relaxation time of the core sample is measured using a nuclear magnetic resonance device. T 2 spectrum sampling, obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 scores; Fitting module is used to match the movable fluid pore throat size characteristics of core samples with the gas flooding stage T 2 spectrum area values ​​to determine the crude oil production scale and T The limit of the difference between the two spectra is equal to zero, and the crude oil production scale and T 2 spectra to interpolate and correlate to determine the scale and T 2. The relationship between the spectra; Determine the module for the water flooding phase T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T The relationship between the two spectra is used to obtain the crude oil production scale in the water drive stage, and the crude oil production scale in the gas drive stage is obtained. T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T 2 spectra, and obtain the crude oil production scale in the gas drive stage.

[0014] The present invention provides a computer-readable storage medium storing a computer program. When the computer program is executed by a processor, the above-mentioned method for evaluating the crude oil production scale of alternating water and gas injection in an unconventional sandstone reservoir is implemented.

[0015] The present invention provides a computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, the method for evaluating the scale of crude oil production in the process of alternating water and gas flooding in unconventional sandstone reservoirs is implemented.

[0016] At least one of the above technical solutions adopted by the present invention can achieve the following beneficial effects: A core sample of an unconventional sandstone standard plunger is prepared and scanned using a computer CT scanning device to obtain the movable fluid pore throat scale characteristics of the core sample; a water-saturated and oil-saturated experiment is conducted on the core sample, and a mixed solution of actual formation water and manganese water and a simulated oil sample are sequentially displaced into the core depth of the core sample using a high-pressure and high-precision plunger pump. The displacement is stopped when the liquid content of the output fluid at the outlet of the core sample reaches a preset threshold, and the original formation oil-water distribution model of the core sample is obtained; a water flooding experiment is conducted on the core sample, and the displacement is stopped when the liquid content of the output fluid at the outlet reaches a preset threshold during the water flooding experiment, and the transverse relaxation time of the core sample is measured using a nuclear magnetic resonance device. T 2 spectrum sampling to obtain the water flooding stageT 2 spectrum; gas drive experiment was carried out on the core sample. When the mass of the output fluid at the outlet no longer changed during the gas drive experiment, the displacement was stopped and the transverse relaxation time of the core sample was measured using nuclear magnetic resonance equipment. T 2 spectrum sampling, obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 spectrum; combined computerized cross-section scanning and nuclear magnetic resonance to accurately evaluate the water-gas alternating displacement process and reveal the internal fluid storage characteristics of unconventional sandstones; compared the movable fluid pore throat size characteristics of core samples with the gas flooding stage T 2 spectrum area values ​​to determine the crude oil production scale and T The limit of the difference between the two spectra is equal to zero. The crude oil production scale and T 2 spectra to interpolate and correlate to determine the scale and T 2 spectra; the relationship between the water flooding stage T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T The relationship between the two spectra is used to obtain the crude oil production scale in the water drive stage, and the crude oil production scale in the gas drive stage is obtained. T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T The relationship between the two spectra is used to obtain the oil production scale during the gas flooding stage. This method can optimize the determination of the pore throat scale of movable fluid during the oil flooding process in unconventional sandstone reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0017] The drawings described herein are used to provide a further understanding of the present invention and constitute a part of the present invention. The exemplary embodiments of the present invention and their descriptions are used to explain the present invention and do not constitute an improper limitation of the present invention. In the drawings:

[0018] Figure 1 A schematic flow chart of a method for evaluating crude oil production scale in an unconventional sandstone reservoir with alternating water and gas injection provided by the present invention; Figure 2 A CT scan frequency area diagram of movable fluid pore throats in an embodiment of the present invention; Figure 3 The crude oil production scale of the No. 1 core sample in an embodiment provided by the present invention is Schematic diagram of the mathematical model of spectrum fitting; Figure 4 A schematic diagram of the crude oil production scale of core sample No. 1 during the water flooding stage in an embodiment of the present invention; Figure 5 A schematic diagram of the crude oil production scale of core sample No. 1 during the gas flooding phase in an embodiment of the present invention; Figure 6A frequency area diagram of movable fluid pore throats scanned by CT in another embodiment of the present invention; Figure 7 The crude oil production scale of the No. 2 core sample in another embodiment provided by the present invention is Schematic diagram of the mathematical model of spectrum fitting; Figure 8 A schematic diagram of the crude oil production scale of core sample No. 2 during the water flooding stage in another embodiment of the present invention; Figure 9 A schematic diagram of the crude oil production scale of core sample No. 2 during the gas flooding phase in another embodiment of the present invention; Figure 10 A frequency area diagram of movable fluid pore throats scanned by CT in another embodiment of the present invention; Figure 11 The crude oil production scale of the No. 3 core sample in another embodiment provided by the present invention is Schematic diagram of the mathematical model of spectrum fitting; Figure 12 A schematic diagram of the crude oil production scale of core sample No. 3 during the water flooding stage in another embodiment of the present invention; Figure 13 A schematic diagram of the crude oil production scale of core sample No. 3 during the gas flooding phase in another embodiment of the present invention; Figure 14 A schematic diagram of a device for determining pore throat production limits for characterizing unconventional sandstone reservoirs during displacement phase provided by the present invention; Figure 15 A schematic diagram of computer equipment for a method for evaluating crude oil production scale by alternating water and gas injection in an unconventional sandstone reservoir provided by the present invention. DETAILED DESCRIPTION

[0019] To make the objectives, technical solutions, and advantages of the present invention more clear, the technical solutions of the present invention will be clearly and completely described below in conjunction with specific embodiments of the present invention and corresponding drawings. Obviously, the embodiments described are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0020] For the convenience of description, the following description only takes the server as the execution subject.

[0021] Unconventional tight sandstone reservoirs possess diverse and highly heterogeneous pore structures, with extremely widespread pore throat distribution and the presence of complex features such as micro- and nano-scale pore throats and microfractures, which profoundly influence fluid flow and interactions. Capillary forces, hysteresis, and multiphase flow compete at extremely small scales, making them difficult to capture using traditional macroscopic parameters. Conventional flooding methods struggle to fully characterize fluid phase changes and interfacial evolution during alternating water-gas flooding.

[0022] Commonly used techniques such as scanning electron microscopy, cast thin sections, and high-pressure mercury injection can reveal some dynamic production information, but are limited by spatial resolution and dynamic response time, making it difficult to achieve continuous and high-precision characterization of crude oil production scales.

[0023] The crude oil production scale reflects the coexistence and dynamic changes of oil, water, and gas three-phase flows in heterogeneous reservoirs, revealing the migration patterns of the oil-water-gas interface and displacement efficiency. Accurately calculating the crude oil production scale not only determines the effective invasion range of injected gas and water fluids and the spatial boundaries of crude oil transformation, but also allows for the rational allocation of the cycle, injection volume, and injection rate of alternating water and gas injection to maximize reservoir development efficiency. Therefore, a method for evaluating the crude oil production scale for alternating water and gas injection in unconventional sandstone reservoirs is needed.

[0024] The technical solutions provided by various embodiments of the present invention are described in detail below with reference to the accompanying drawings.

[0025] Figure 1 The flow chart of the method for evaluating the crude oil production scale of alternating water and gas injection in unconventional sandstone reservoirs according to the present invention is as follows: S101: Prepare core samples of unconventional sandstone standard plugs and scan them using a computerized cross-sectional CT scanner to obtain the movable fluid pore throat scale characteristics of the core samples.

[0026] The movable fluid pore throat scale characteristic of the core is the proportion of the number of movable fluid pore throats of different scales in the total number of movable fluid pore throats.

[0027] In an exemplary embodiment, a process for preparing core samples for unconventional sandstone standard plugs specifically includes: screening, classifying, and numbering selected unconventional sandstone cores to determine test cores; The test cores were cleaned continuously for 10 days using benzene and petroleum ether in a ratio of 3:1 at 5 MPa and 80°C. The cleaned test cores were dried in an 80°C constant temperature box for 24 hours. After drying, the test cores were cut and polished to produce core samples of unconventional sandstone standard plungers with a preset length and diameter.

[0028] Specifically, the first preset length and the first preset diameter are set according to specific engineering practices. For example, the first preset length is set to 8.0 cm , the first preset diameter is set to 2.5 cm.

[0029] Specifically, the preparation of core samples for standard plugs of unconventional sandstone is divided into two steps.

[0030] Step 1: Dry the washing oil, screen, classify and number the selected cores, and use benzene and petroleum ether in a ratio of 3:1 at 5 MPa , 80 ℃ The cores were cleaned continuously for 10 days under the following conditions. After cleaning, the cores were placed in a constant temperature box for drying at 80 ℃ The rock samples were dried for 24 hours.

[0031] Step 2: Test the physical properties, cut and polish the core and make it into a length of 8.0 cm × diameter 2.5 cm The core samples are collected and numbered, and the porosity and permeability of the rock samples are measured as required according to the method for measuring the porosity and permeability of rocks under overburden pressure.

[0032] Step 3: Determine the distribution scale of the movable fluid pore throats. Use a computerized tomography (CT) device to scan the core sample to obtain the movable fluid pore throat scale parameters of the core sample.

[0033] S102: Perform water-saturated and oil-saturated experiments on the core sample. Use a high-pressure, high-precision plunger pump to sequentially displace a mixed solution of actual formation water and manganese water and a simulated oil sample deep into the core of the core sample. Stop displacement when the liquid content of the output fluid at the outlet of the core sample reaches a preset threshold, and obtain the original formation oil-water distribution model of the core sample.

[0034] In an exemplary embodiment, the core samples include core samples No. 1, No. 2, and No. 3; a saturated water experiment is performed on the core samples, specifically including: displacing a mixed solution of actual formation water (36310.85 mg / L, CaCl2) and manganese water (25000 mg / L, MnCl2) into the deep core at a temperature of 70°C, a displacement rate of 0.10 mL / min, and a displacement pressure of 15 MPa; stopping the displacement when the liquid content of the outlet output fluid reaches 10PV during the displacement process, and obtaining the original formation water distribution model of the core sample.

[0035] Specifically, an original formation water distribution model was established. The core samples were placed in a high-temperature and high-pressure physical flow simulation experimental device system. A high-pressure and high-precision plunger pump was used to displace a mixed solution of actual formation water and manganese water into the deep core. The actual formation water was 36310.85 mg / L, CaCl2, and the manganese water was 25000 mg / L, MnCl2. The temperature was constant at 70°C, the displacement rate was 0.10 mL / min, the displacement pressure was 15 MPa, and the confining pressure was set to 17 MPa using a confining pressure pump. When the liquid content of the outlet output fluid reached 10PV during the saturated water experiment, saturation was stopped to establish the original formation water distribution model of the experimental core samples.

[0036] In an exemplary embodiment, unconventional sandstone standard plug core samples include core samples No. 1, No. 2, and No. 3; an oil saturation experiment is performed on the core samples, specifically including: after simulating the original formation water distribution, the simulated oil sample is driven into the core depth at a temperature of 70°C, a displacement rate of 0.10 mL / min, and a displacement pressure of 18 MPa; the displacement is stopped when the liquid content of the output fluid at the outlet reaches 10PV during the displacement process; and the core samples are subjected to nuclear magnetic resonance. T 2 spectrum sampling to establish the original formation oil and water distribution model of the core sample.

[0037] Specifically, the original formation oil-water distribution model was established, and the simulated oil sample was driven to the deep core by a high-pressure and high-precision plunger pump to replace the actual formation water and manganese aqueous solution. The temperature was kept constant at 70 ° C, the displacement rate was 0.10 mL / min, the displacement pressure was 18 MPa, and the confining pressure was set to 20 MPa by a confining pressure pump. During the saturated oil experiment, the saturation was stopped when the liquid content of the outlet output fluid reached 10PV to establish the original formation oil-water distribution model of the core sample, and then nuclear magnetic resonance was performed. T 2. Spectral sampling is used to obtain the saturated oil signal intensity area value.

[0038] S103: Perform a water flooding experiment on the core sample. When the liquid content of the output fluid at the outlet reaches a preset threshold during the water flooding experiment, the flooding is stopped, and a nuclear magnetic resonance device is used to perform a transverse relaxation time on the core sample. T 2 spectrum sampling to obtain the water flooding stage T 2 scores.

[0039] In an exemplary embodiment, the core samples include core samples No. 1, No. 2, and No. 3; a water flooding experiment is conducted on the unconventional sandstone core samples for establishing the original formation oil-water distribution model to obtain the water flooding stage. T 2 Spectrum area value and water flooding stage T2 spectra, specifically including: displacing actual formation water to the deep core at a temperature of 70°C and a displacement rate of 0.10 mL / min; setting the displacement pressures of core samples No. 1, No. 2, and No. 3 to 8 MPa, 15 MPa, and 22 MPa, respectively; using a confining pressure pump to set the confining pressures of core samples No. 1, No. 2, and No. 3 to 10 MPa, 17 MPa, and 24 MPa, respectively; stopping the displacement when the water content of the output fluid at the outlet of core samples No. 1, No. 2, and No. 3 is above 98%; conducting water flooding experimental nuclear magnetic resonance T 2 spectrum sampling, to obtain the water flooding stage T 2 Spectrum area value and water flooding stage T 2 scores.

[0040] Specifically, in the water flooding experiment, the actual formation water was displaced to the deep core, the temperature was kept constant at 70°C, the displacement rate was 0.10 mL / min, the displacement pressures of cores 1, 2, and 3 were set to 8 MPa, 15 MPa, and 22 MPa, respectively, and the confining pressure pump was used to set the confining pressures to 10 MPa, 17 MPa, and 24 MPa, respectively. The displacement was stopped when the water content of the outlet output fluid reached 98%, and the water flooding signal intensity area value was obtained.

[0041] The pressures applied to core samples No. 1, No. 2 and No. 3 in the water flooding experiment were different. The core samples obtained under different pressure settings T 2 The scores are different.

[0042] S104: Perform a gas drive experiment on the core sample. When the quality of the output fluid at the outlet no longer changes during the gas drive experiment, stop the displacement and use a nuclear magnetic resonance device to measure the transverse relaxation time of the core sample. T 2 spectrum sampling, obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 scores.

[0043] In an exemplary embodiment, the core samples include core samples No. 1, No. 2, and No. 3; a gas drive experiment is performed on the core samples to obtain the gas drive stage. T 2 Spectral area value and NMR of gas flooding stage T 2 spectra, specifically including: setting the temperature to a constant 70°C and the displacement rate to 0.10mL / min; using a high-pressure and high-precision plunger pump to set the CO2 injection pressure of core samples No. 1, No. 2 and No. 3 to 8MPa, 15MPa and 22MPa respectively, and using a confining pressure pump to set the confining pressure of core samples No. 1, No. 2 and No. 3 to 10MPa, 17MPa and 24MPa respectively; making CO2 in supercritical state, near miscible state and miscible state, respectively, to conduct CO2 flooding physical flow simulation experiments on core samples No. 1, 2 and 3, and stopping the displacement at each stage when the output fluid quality at the outlet no longer changes; performing nuclear magnetic resonance after multiphase CO2 displacement T2 spectrum sampling, to obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 scores.

[0044] Specifically, the gas drive experiment temperature was set at 70°C, the displacement rate was set at 0.10 mL / min, and the CO2 injection pressures of core samples No. 1, No. 2, and No. 3 were set to 8 MPa, 15 MPa, and 22 MPa, respectively, using a high-pressure, high-precision plunger pump. The CO2 was placed in supercritical, near-miscible, and miscible states to conduct a physical flow simulation experiment of CO2 flooding. The displacement was stopped at each stage when the quality of the output fluid at the outlet no longer changed, in order to obtain the CO2 displacement in different phases. T 2 Spectral area value.

[0045] The pressures applied to core samples No. 1, No. 2 and No. 3 in the gas drive experiment were 8 MPa, 15 MPa and 22 MPa respectively. T 2 The scores are different.

[0046] S105: Compare the movable fluid pore throat characteristics of the core sample with the gas flooding stage T 2 spectrum area values ​​to determine the crude oil production scale and T The limit of the difference between the two spectra is equal to zero. The crude oil production scale and T 2 spectra to interpolate and correlate to determine the scale and T 2 The relationship between the spectra.

[0047] In an exemplary embodiment, the crude oil production scale is T The process of constructing the relationship between the 2 spectra specifically includes: When the core sample is saturated with a single-phase fluid, the preliminary expression of the fluid relaxation rate is shown in formula (1): (1); in, represents the relaxation time in ms, represents the transverse surface relaxation intensity, in μm / ms, Represents the pore surface area in cm 2 , Represents the pore volume in cm 3 , Represents the diffusion coefficient, in μm 2 / ms, represents the magnetic gyrometry ratio, Represents the echo interval, in ms, Represents the magnetic field gradient, in units of T / cm, Represents the transverse volume relaxation time, in ms.

[0048] However, in porous media, the transverse volume relaxation rate of the fluid is significantly lower than the transverse surface relaxation rate; at the same time, the magnetic field gradient is small, so the diffusion relaxation term of the actual fluid is ignored ( ), volume relaxation term ( ), the relaxation rate of a single-phase fluid in a uniform magnetic field is determined as shown in formula (2): (2); In addition, according to the pore radius being equal to the product of the movable fluid pore throat radius and the pore throat ratio, T 2. There is a significant power exponential relationship between relaxation time and crude oil production scale, so it is determined T The preliminary expression of the 2 spectrum is shown in formula (3): (3); in, r represents the crude oil production scale, in μm; n is the power index, F t represents the average pore-throat ratio of rock pores, F s represents the pore shape factor.

[0049] right T 2 spectrum is solved, and the expression of crude oil production scale is obtained as shown in formula (4): (4).

[0050] Define the expression of crude oil production scale , then determine the crude oil production scale and T The preliminary relationship between the two spectra is shown in formula (5): (5).

[0051] draw T 2 spectrum and the cumulative distribution curve of crude oil production scale, and select the production scale and transverse relaxation time for interpolation correlation, and solve the parameters in the relationship by the least squares method C and n ; The formula corresponding to the least squares method is shown in formula (6): (6).

[0052] The least squares method is used to obtain C and n Substitute the crude oil utilization scale and T The preliminary relationship between the two spectra is used to obtain the crude oil production scale and T 2 The relationship between the spectra.

[0053] Specifically, the injection pressures of core samples No. 1, No. 2, and No. 3 during the gas drive experiment were 8 MPa, 15 MPa, and 22 MPa, respectively. T 2 spectra are different, so according to the signal intensity area value and movable fluid pore throat scale under different pressure settings, the crude oil production scale and T The set of solutions where the limit of the difference between the two spectra is equal to zero.

[0054] In an exemplary embodiment, determining the crude oil production scale and T The solution set where the limit of the difference between the two spectra is equal to zero includes: finding the solution that satisfies the different movable fluid pore throat sizes and T 2 The limiting value of the spectral integral, formula (7) is as follows: (7); in, is the movable fluid pore throat size of the core sample, i is the frequency, x is the frequency value point, For the gas drive stage T 2 spectral curves, is the minimum relaxation time, is the maximum relaxation time.

[0055] The different movable fluid pore throat sizes and T 2 The limit value of the spectrum integral is determined as the scale of crude oil production and T The set of solutions where the limit of the difference between the two spectra is equal to zero.

[0056] Specifically, the frequency values ​​of the movable fluid pore throat scale are arranged in order from small to large, and the values ​​obtained from the gas flooding experiment are T 2. The spectrum signal strength is arranged in ascending order, and the crude oil production scale and T 2 spectrum value, obtain crude oil production scale and T The limit of the difference between the two spectra is equal to the limit value of zero as the solution set.

[0057] In an exemplary embodiment, the crude oil production scale is T The number of solution sets whose limit of the difference between the two spectra is equal to zero ranges from a first preset value to a second preset value and is uniformly distributed.

[0058] Specifically, the first preset value and the second preset value are set according to specific engineering practices. For example, in the present invention, the first preset value is set to 1, and the second preset value is set to 100.

[0059] S106: The water flooding stage T2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T The relationship between the two spectra is used to obtain the crude oil production scale in the water drive stage, and the crude oil production scale in the gas drive stage is obtained. T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T 2 spectra, and obtain the crude oil production scale in the gas drive stage.

[0060] Specifically, the injection pressures of core samples No. 1, No. 2, and No. 3 during the water flooding experiment were different. T The 2 spectra are different. The water flooding stages are 8MPa, 15MPa, and 22MPa respectively. T The initial value and cutoff value of the 2 spectrum are substituted into the objective function of crude oil production scale and relaxation time to obtain the crude oil production scale in the water flooding stage.

[0061] Specifically, the injection pressures of core samples No. 1, No. 2, and No. 3 during the gas drive phase were different. The core samples obtained under different injection pressures were T The two spectra are different, and the gas drive stages of 8MPa, 15MPa and 22MPa are respectively T The initial value and cutoff value of the 2 spectrum are substituted into the objective function of crude oil production scale and relaxation time to obtain the crude oil production scale in the gas flooding stage.

[0062] When applying the method for evaluating the production scale of crude oil in an unconventional sandstone reservoir with alternating water and gas injection provided by the present invention, it is not necessary to Figure 1 The steps are executed in the order shown. The specific execution order of the steps can be determined according to needs, and the present invention does not limit this.

[0063] In one embodiment of the present invention, a method for evaluating the production scale of crude oil in an unconventional sandstone reservoir with alternating water and gas injection includes the following steps: Step 1, drying and oil washing: the selected cores were screened, classified and numbered, and cleaned continuously for 10 days with benzene and petroleum ether in a ratio of 3:1 at 5 MPa and 80 °C. After cleaning, the cores were placed in a constant temperature box for drying, and the rock samples were dried at 80 °C for 24 hours.

[0064] Step 2: Test physical properties: Cut and polish the core to make core samples with a length of 8.0 cm and a diameter of 2.5 cm. The core samples are numbered and the porosity and permeability of the rock samples are measured to be 12.94% and 0.15 mD, respectively.

[0065] Step 3: Determination of movable fluid pore throat size: Perform CT scanning on core sample No. 1 to obtain the movable fluid pore throat size characteristics of core sample No. 1, such as Figure 2 As shown, the horizontal axis is the pore throat scale of the movable fluid, and the vertical axis is the scale frequency. Figure 2A frequency area diagram of movable fluid pore throats scanned by CT scan in an embodiment of the present invention.

[0066] Step 4. Establish a formation water distribution model: Place the core in a high-temperature and high-pressure physical flow simulation experimental device, and use a high-pressure and high-precision plunger pump to displace a mixed solution of actual formation water and manganese water into the deep core. The formation water content is 36310.85 mg / L, CaCl2, and the manganese water is 25000 mg / L, MnCl2. The temperature is constant at 70°C, the displacement rate is 0.10 mL / min, the displacement pressure is 15 MPa, and the confining pressure is set to 17 MPa using a confining pressure pump. Saturation is stopped when the injection volume reaches 10PV, and the original formation water distribution model of the experimental core is established.

[0067] Step 5. Establish the original oil-water distribution model: Use a high-pressure and high-precision plunger pump to displace the simulated oil sample into the deep core to replace the formation water solution. The simulated oil sample (crude oil: kerosene, 1:3) is kept at a constant temperature of 70°C, a displacement rate of 0.10mL / min, a displacement pressure of 18MPa, and a confining pressure pump set to 20MPa until the oil content of the outlet output fluid reaches 98%. Saturated oil nuclear magnetic resonance T 2 spectrum sampling to establish the oil-water distribution model of the original formation in the experimental core.

[0068] Step 6: Water flooding stage: The actual formation water is driven to the deep core, the temperature is kept constant at 70℃, the displacement rate is 0.10mL / min, the displacement pressure of core sample No. 1 is set to 8MPa, and the confining pressure is set to 10MPa using the confining pressure pump. When the water content of the output fluid at the outlet reaches 98%, the displacement is stopped and the water flooding experiment nuclear magnetic resonance is performed. T 2 spectrum sampling to obtain the water flooding signal intensity area value.

[0069] Step 7, gas drive stage: the temperature is kept constant at 70℃, the displacement rate is 0.10mL / min, and the CO2 injection pressure of the No. 1 core sample is set to 8MPa using a high-pressure and high-precision plunger pump. The physical flow simulation experiment of CO2 oil displacement is carried out in a supercritical state. The displacement is stopped when the quality of the output fluid at the outlet no longer changes. The nuclear magnetic resonance after displacement is performed. T 2 spectrum sampling, and obtain the gas drive signal intensity area value, which is the signal intensity area value mentioned above. T 2 Spectral area value.

[0070] Step 8. If an error occurs during the experiment, repeat steps 4 to 7 until the experiment is correct.

[0071] Step 9: T 2 spectrum and the conversion of movable fluid pore throat, and find the equation (7) that is valid. Value and i Values, and for the multiple groups found Value andi Value fitting, Figure 3 The crude oil production scale of the No. 1 core sample in an embodiment provided by the present invention is Schematic diagram of the power function model for value fitting, such as Figure 3 As shown, we can get C=0.329, n -1 =0.849, crude oil utilization scale and T The relationship between the two spectra is shown in formula (8): (8); in, is the crude oil utilization scale, is the relaxation time.

[0072] Step 10: Water Drive Stage T Substituting the initial value (0.014 ms) and cutoff value (1683.18 ms) of the 2 spectrum into formula (8), the lower limit of crude oil production in the water flooding stage (8.78×10 −3 μm), the upper limit of crude oil production in the water flooding stage (180.377 μm), Figure 4 Schematic diagram of crude oil production scale of core sample No. 1 in the water drive stage in an embodiment provided by the present invention; T Substituting the initial value (0.008 ms) and cutoff value (460.592 ms) of the 2 spectrum into formula (8), the lower limit of crude oil production in the gas drive stage (5.46×10 −3 μm), the upper limit of crude oil production in the gas drive stage (60.028 μm), Figure 5 A schematic diagram of the crude oil production scale of core sample No. 1 during the gas drive stage in an embodiment provided by the present invention.

[0073] In another embodiment of the present invention, a method for evaluating crude oil production scale during alternating water and gas injection in an unconventional sandstone reservoir includes the following steps: Step 1, drying and oil washing: the selected cores were screened, classified and numbered, and cleaned continuously for 10 days with benzene and petroleum ether in a ratio of 3:1 at 5 MPa and 80 °C. After cleaning, the cores were placed in a constant temperature box for drying, and the rock samples were dried at 80 °C for 24 hours.

[0074] Step 2: Test physical properties: Cut and polish the core to make core samples with a length of 8.0 cm and a diameter of 2.5 cm. The core samples are numbered and the porosity and permeability of the rock samples are measured to be 14.05% and 0.28 mD, respectively.

[0075] Step 3: Determination of movable fluid pore throat size: Perform CT scanning on core sample No. 2 to obtain the movable fluid pore throat size characteristics of core sample No. 2, such as Figure 6As shown, the horizontal axis is the pore throat scale of the movable fluid, and the vertical axis is the scale frequency. Figure 6 A frequency area diagram of movable fluid pore throats obtained by CT scanning in another embodiment of the present invention.

[0076] Step 4. Establish a formation water distribution model: Place the core into a high-temperature and high-pressure physical flow simulation experimental device, and use a high-pressure and high-precision plunger pump to displace a mixed solution of actual formation water and manganese water into the deep core. The formation water content is 36310.85 mg / L, CaCl2 water type, and the manganese water is 25000 mg / L, MnCl2. The temperature is set to 70°C, the injection rate is 0.10 mL / min, and the injection pressure is 15 MPa. The confining pressure pump is used to set the confining pressure to 17 MPa. When the injection volume reaches 10PV, saturation is stopped to establish the original formation water distribution model of the experimental core sample.

[0077] Step 5. Establish the original oil-water distribution model: Use a high-pressure and high-precision plunger pump to displace the simulated oil sample into the deep core to replace the formation water solution. The simulated oil sample (crude oil: kerosene, 1:3) is kept at a constant temperature of 70°C, a displacement rate of 0.10mL / min, a displacement pressure of 18MPa, and a confining pressure pump set to 20MPa until the oil content of the outlet output fluid reaches 98%. Saturated oil nuclear magnetic resonance T 2 spectrum sampling to establish the oil-water distribution model of the original formation in the experimental core.

[0078] Step 6: Water flooding stage: The actual formation water was driven to the deep core, the temperature was kept constant at 70℃, the displacement rate was 0.10mL / min, the displacement pressure of core sample No. 2 was set to 15MPa, and the confining pressure pump was used to set the confining pressure to 17MPa. When the water content of the output fluid at the outlet reached 98%, the displacement was stopped and the water flooding experiment nuclear magnetic resonance was performed. T 2 spectrum sampling to obtain the water flooding signal intensity area value.

[0079] Step 7, gas drive stage: the temperature is kept constant at 70℃, the displacement rate is 0.10mL / min, and the CO2 injection pressure of core 2 is set to 15MPa using a high-pressure and high-precision plunger pump. The physical flow simulation experiment of CO2 oil displacement is carried out in a near-miscible state. The displacement is stopped when the quality of the output fluid at the outlet no longer changes. The nuclear magnetic resonance after displacement is performed. T 2 spectrum sampling to obtain the gas drive signal intensity area value.

[0080] Step 8: If an error occurs during the experiment, repeat steps 4 to 7 in this embodiment until the experiment is correct.

[0081] Step 9: T 2 spectrum and the conversion of movable fluid pore throat, and find the equation (7) that is valid. Value and i Values, and for the multiple groups found Value and i Value fitting, Figure 7 The crude oil production scale of the No. 2 core sample in another embodiment provided by the present invention is Schematic diagram of the power function model for value fitting, such as Figure 7 As shown, we can get C=0.61, n -1 =1.036, crude oil mobilization scale and T The relationship between the two spectra is shown in formula (9): (9); in, For rock mobilization scale, is the relaxation time.

[0082] Step 10: Water Drive Stage T Substituting the initial value (0.010 ms) and cutoff value (424.757 ms) of the 2 spectrum into formula (9), the lower limit of crude oil production in the water flooding stage (5.17×10 −3 μm), the upper limit of crude oil production in the water flooding stage (322.169 μm), Figure 8 Schematic diagram of crude oil production scale of core sample No. 2 in the water drive stage in an embodiment of the present invention; T Substituting the initial value (0.005 ms) and cutoff value (261.268 ms) of the 2 spectrum into formula (9), the lower limit of crude oil production in the gas drive stage (2.52×10 −3 μm), upper limit of crude oil production in gas drive stage (194.729 μm), Figure 9 A schematic diagram of the crude oil production scale of core sample No. 1 during the gas drive stage in an embodiment provided by the present invention.

[0083] In one embodiment of the present invention, a method for evaluating the production scale of crude oil in an unconventional sandstone reservoir with alternating water and gas injection includes the following steps: Step 1, drying and oil washing: the selected cores were screened, classified and numbered, and cleaned continuously for 10 days with benzene and petroleum ether in a ratio of 3:1 at 5 MPa and 80 °C. After cleaning, the cores were placed in a constant temperature box for drying, and the rock samples were dried at 80 °C for 24 hours.

[0084] Step 2: Test physical properties: Cut and polish the core to make core samples with a length of 8.0 cm and a diameter of 2.5 cm. The core samples are numbered and the porosity and permeability of the rock samples are measured to be 15.27% and 0.33 mD, respectively.

[0085] Step 3: Determination of movable fluid pore throat size: Perform CT scanning on core sample No. 1 to obtain the movable fluid pore throat size characteristics of core sample No. 1, such as Figure 10As shown, the horizontal axis is the pore throat scale of the movable fluid, and the vertical axis is the scale frequency. Figure 10 A frequency area diagram of movable fluid pore throats scanned by CT scan in an embodiment of the present invention.

[0086] Step 4. Establish a formation water distribution model: Place the core sample in a high-temperature and high-pressure physical flow simulation experimental device, and use a high-pressure and high-precision plunger pump to displace a mixed solution of actual formation water and manganese water into the deep core. The actual formation water is 36310.85 mg / L, CaCl2, and the manganese water is 25000 mg / L, MnCl2. The temperature is constant at 70°C, the displacement rate is 0.10 mL / min, the displacement pressure is 15 MPa, and the confining pressure is set to 17 MPa using a confining pressure pump. Saturation is stopped when the injection volume reaches 10PV, and the original formation water distribution model of the experimental core is established.

[0087] Step 5. Establish the original oil-water distribution model: Use a high-pressure and high-precision plunger pump to displace the simulated oil sample into the deep core to replace the formation water solution. The simulated oil sample (crude oil: kerosene, 1:3) is kept at a constant temperature of 70°C, a displacement rate of 0.10mL / min, a displacement pressure of 18MPa, and a confining pressure pump set to 20MPa until the oil content of the outlet output fluid reaches 98%. Saturated oil nuclear magnetic resonance T 2 spectrum sampling to establish the oil-water distribution model of the original formation in the experimental core.

[0088] Step 6: Water flooding stage: The actual formation water is driven to the deep core, the temperature is kept constant at 70℃, the displacement rate is 0.10mL / min, the displacement pressure of core No. 3 is set to 22MPa, and the confining pressure is set to 24MPa using the confining pressure pump. When the water content of the output fluid at the outlet reaches 98%, the displacement is stopped and the water flooding experiment nuclear magnetic resonance is performed. T 2 spectrum sampling to obtain the water flooding signal intensity area value.

[0089] Step 7, gas drive stage: the temperature is kept constant at 70℃, the displacement rate is 0.10mL / min, and the CO2 injection pressure of the No. 3 core sample is set to 22MPa using a high-pressure and high-precision plunger pump. The physical flow simulation experiment of CO2 oil displacement is carried out in a mixed phase state. The displacement is stopped when the output fluid quality at the outlet no longer changes. The nuclear magnetic resonance after displacement is performed. T 2 spectrum sampling to obtain the gas drive signal intensity area value.

[0090] Step 8: If an error occurs during the experiment, repeat steps 4 to 7 in this embodiment until the experiment is correct.

[0091] Step 9: T 2 spectrum and the conversion of movable fluid pore throat, and find the equation (7) that is valid. Value and i Values, and for the multiple groups found Value and i Value fitting, Figure 11 The crude oil production scale of the No. 3 core sample in an embodiment provided by the present invention is Schematic diagram of the power function model for value fitting, such as Figure 11 As shown, we can get C=0.543, n -1 =1.013, crude oil mobilization scale and T The relationship between the two spectra is shown in formula (10): (10); in, is the crude oil utilization scale, is the relaxation time.

[0092] Step 10: Water Drive Stage T Substituting the initial value (0.006 ms) and cutoff value (307.211 ms) of the 2 spectrum into formula (10), the lower limit of crude oil production in the water flooding stage (3.27×10 −3 μm), the upper limit of crude oil production in the water flooding stage (179.711 μm), Figure 12 Schematic diagram of crude oil production scale of core sample No. 3 in the water drive stage in an embodiment of the present invention; T Substituting the initial value (0.002 ms) and cutoff value (222.195 ms) of the 2 spectrum into formula (10), the lower limit of crude oil production in the gas drive stage (1.00×10 −3 μm), upper limit of crude oil production in gas drive stage (129.432 μm), Figure 13 A schematic diagram of the crude oil production scale of core sample No. 3 during the gas drive stage in an embodiment provided by the present invention.

[0093] Unconventional tight sandstone reservoirs have diverse pore structures and strong heterogeneity, with extremely wide distribution of pore throats and complex features such as micro-nanoscale pore throats and microcracks, which have a profound impact on fluid seepage and interaction. In order to reduce the error in pore throat utilization judgment in the multiphase displacement process, the present invention proposes a method for evaluating the scale of crude oil utilization in unconventional sandstone reservoirs with alternating water and gas injection. This method uses a combination of computerized cross-sectional scanning and nuclear magnetic resonance technology to achieve micro-nanoscale characterization of movable fluid pore throats: a high-precision scanner is used to perform cross-sectional scanning on the core samples to clarify the distribution characteristics of the movable fluid pore throats; then a water-gas alternating displacement experiment is carried out, and a low-field nuclear magnetic resonance instrument is used to collect transverse relaxation time after each stage. T 2 spectrum, accurately capture the pore throat size of movable fluid under the action of different displacement media; by constructing the pore throat size of movable fluid and nuclear magnetic resonance T2 spectra, solve the limit condition that the difference between the two approaches zero, and fit the objective function with clear physical meaning; finally, the T Substituting the initial and cutoff values ​​of the 2-spectrum into the objective function, the critical pore throat radius of the movable fluid under the water-gas alternation mode was calculated. This scheme combines the advantages of pore throat structure obtained by computerized cross-section scanning with the dynamic monitoring capabilities of nuclear magnetic resonance (NMR), providing precise movable fluid pore throat scale parameters for the efficient development of unconventional sandstone reservoirs.

[0094] The above is a method for evaluating the scale of crude oil production in an unconventional sandstone reservoir during alternating water-gas injection provided by an embodiment of the present invention. In addition, the present invention also provides a device for evaluating the scale of crude oil production in an unconventional sandstone reservoir during alternating water-gas injection. Figure 14 shown.

[0095] Figure 14 A schematic diagram of a crude oil production scale evaluation device for alternating water and gas injection in an unconventional sandstone reservoir provided by the present invention includes: The acquisition module 1401 is used to prepare a core sample of an unconventional sandstone standard plunger and scan the core sample using a computerized cross-section (CT) scanning device to obtain the movable fluid pore throat scale characteristics of the core sample.

[0096] Module 1402 is established to conduct water-saturated and oil-saturated experiments on the core sample. A mixed solution of actual formation water and manganese water and a simulated oil sample are sequentially displaced into the core depth of the core sample using a high-pressure, high-precision plunger pump. The displacement is stopped when the liquid content of the output fluid at the outlet of the core sample reaches a preset threshold, thereby obtaining the original formation oil-water distribution model of the core sample.

[0097] The water flooding module 1403 is used to conduct water flooding experiments on core samples. When the liquid content of the output fluid at the outlet reaches a preset threshold during the water flooding experiment, the flooding is stopped and the transverse relaxation time of the core sample is measured using a nuclear magnetic resonance device. T 2 spectrum sampling to obtain the water flooding stage T 2 scores.

[0098] The gas drive module 1404 is used to perform a gas drive experiment on the core sample. When the quality of the output fluid at the outlet no longer changes during the gas drive experiment, the displacement is stopped and the transverse relaxation time of the core sample is measured using a nuclear magnetic resonance device. T 2 spectrum sampling, obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 scores.

[0099] Fitting module 1405 is used to fit the movable fluid pore throat scale characteristics of the core sample to the gas drive stage T 2 spectrum area values ​​to determine the crude oil production scale andT The limit of the difference between the two spectra is equal to zero, and the crude oil production scale and T 2 spectra to interpolate and correlate to determine the scale and T 2 The relationship between the spectra.

[0100] Determine module 1406, for the water flooding stage T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T The relationship between the two spectra is used to obtain the crude oil production scale in the water drive stage, and the crude oil production scale in the gas drive stage is obtained. T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T 2 spectra, and obtain the crude oil production scale in the gas drive stage.

[0101] Regarding the device for evaluating the scale of crude oil production by alternating water and gas injection in an unconventional sandstone reservoir, please refer to the definition of the method for evaluating the scale of crude oil production by alternating water and gas injection in an unconventional sandstone reservoir above, which will not be repeated here. Each module in the above-mentioned device for evaluating the scale of crude oil production by alternating water and gas injection in an unconventional sandstone reservoir can be implemented in whole or in part through software, hardware, or a combination thereof. Each of the above-mentioned modules can be embedded in or independent of the processor in the computer device in the form of hardware, or can be stored in the memory of the computer device in the form of software, so that the processor can call and execute the corresponding operations of each of the above modules.

[0102] The present invention also provides a computer-readable storage medium, which stores a computer program, which can be used to execute the above Figure 1 A method for evaluating the crude oil production scale of alternating water and gas injection in unconventional sandstone reservoirs is provided.

[0103] The present invention also provides Figure 15 The structural diagram of the computer equipment shown in FIG. Figure 15 As shown in FIG, at the hardware level, the computer device includes a processor, an internal bus, a network interface, a memory, and a non-volatile memory. The processor reads the corresponding computer program from the non-volatile memory into the memory and then runs it to achieve the above Figure 1 A method for evaluating the scale of crude oil production in unconventional sandstone reservoirs with alternating water and gas injection is provided.

[0104] Those skilled in the art will appreciate that all or part of the processes in the above-described method embodiments can be implemented by instructing the relevant hardware through a computer program. The computer program can be stored in a non-volatile computer-readable storage medium. When executed, the computer program can include the processes in the above-described method embodiments. Any reference to memory, storage, database, or other media used in the various embodiments provided herein may include at least one of non-volatile and volatile memory. Non-volatile memory may include read-only memory (ROM), magnetic tape, floppy disk, flash memory, or optical storage. Volatile memory may include random access memory (RAM) or external cache memory. By way of illustration and not limitation, RAM can take various forms, such as static random access memory (SRAM) or dynamic random access memory (DRAM).

[0105] The technical features of the above embodiments can be combined arbitrarily. To make the description concise, not all possible combinations of the technical features in the above embodiments are described; however, as long as there is no contradiction in the combination of these technical features, they should be considered to be within the scope of the present invention.

Claims

1. A method for evaluating the scale of crude oil production by alternating water and gas injection in unconventional sandstone reservoirs, characterized in that: include: Prepare core samples of unconventional sandstone standard plugs and scan them using computerized cross-sectional CT scanning equipment to obtain the movable fluid pore throat scale characteristics of the core samples; Water-saturated and oil-saturated experiments were conducted on the core samples. A mixed solution of actual formation water and manganese water, and a simulated oil sample were sequentially displaced deep into the core of the core sample using a high-pressure, high-precision plunger pump. Displacement was stopped when the liquid content of the output fluid at the core sample outlet reached a preset threshold, resulting in a model of the original formation oil and water distribution of the core sample. A water flooding experiment was conducted on the core sample. When the liquid content of the output fluid at the outlet reached the preset threshold during the water flooding experiment, the flooding was stopped and the transverse relaxation time of the core sample was measured using a nuclear magnetic resonance device. T 2 spectrum sampling to obtain the water flooding stage T 2 spectrums; A gas drive experiment was conducted on the core sample. When the mass of the output fluid at the outlet no longer changed during the gas drive experiment, the displacement was stopped and the transverse relaxation time of the core sample was measured using a nuclear magnetic resonance device. T 2 spectrum sampling to obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 spectrums; The movable fluid pore throat size characteristics of the core samples were compared with those of the gas flooding stage. T 2 spectrum area values ​​to determine the crude oil production scale and T The limit of the difference between the two spectra is equal to zero. The crude oil production scale and T 2 spectra to interpolate and correlate to determine the scale and T 2. The relationship between the spectra; The water flooding stage T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T The relationship between the two spectra is used to obtain the crude oil production scale in the water drive stage, and the crude oil production scale in the gas drive stage is obtained. T 2. Substitute the initial value and cutoff value of the spectrum into the crude oil production scale and T 2 spectra, and obtain the crude oil production scale in the gas drive stage.

2. The method according to claim 1, wherein Crude oil utilization scale and T The process of constructing the relationship between the 2 spectra specifically includes: When the core sample is saturated with a single-phase fluid, the preliminary expression for the relaxation rate of the fluid is expressed as: ； in, is the relaxation rate of the fluid, represents the relaxation time, represents the transverse surface relaxation strength, represents the pore surface area, represents the pore volume, represents the diffusion coefficient, represents the magnetic gyrometry ratio, represents the echo interval, represents the magnetic field gradient, represents the transverse bulk relaxation time; Ignore the diffusion relaxation term of the actual fluid , volume relaxation term , the relaxation rate of a single-phase fluid in a uniform magnetic field is determined as: ； According to the pore radius is equal to the product of the movable fluid pore throat radius and the pore throat ratio, T 2 There is a significant power exponential relationship between relaxation time and crude oil production scale, which can be determined T The preliminary expression of 2 spectrum is: ； in, r Represents the scale of crude oil mobilization, n is the power index, F t represents the average pore-throat ratio of rock pores, F s represents the pore shape factor; right T 2 spectrum is solved, and the expression of crude oil utilization scale is obtained as follows: ； Define the expression of crude oil production scale , then determine the crude oil production scale and T The preliminary relationship between the two spectra is: ； draw T 2 spectrum and the cumulative distribution curve of crude oil production scale, and select the production scale and transverse relaxation time for interpolation correlation, and solve the parameters in the relationship by the least squares method C and n ; The formula corresponding to the least squares method is: ； The least squares method is used to obtain C and n Substitute the crude oil utilization scale and T The preliminary relationship between the two spectra is used to obtain the crude oil production scale and T 2 The relationship between the spectra.

3. The method according to claim 1, wherein Determine the scale of crude oil production and T The solution set where the limit of the difference between the two spectra is equal to zero includes: Obtain crude oil utilization scale and T The limit of the difference between two spectra is: ； in, is the pore throat scale characteristic of the movable fluid in the core sample, i is the frequency, x is the frequency value point, For the displacement stage T 2 spectral curves, is the minimum relaxation time, is the maximum value of relaxation time; The found movable fluid pore throat size and T 2 The limit value of the spectrum integral is determined as the crude oil production scale and T 2 The solution set of the spectrum.

4. The method according to claim 3, wherein Crude oil utilization scale and T The number of solution sets of the 2-spectrum ranges from a first preset value to a second preset value and is uniformly distributed.

5. The method according to claim 1, wherein The process for preparing core samples for standard plungers of unconventional sandstone includes: Screen, classify and number the selected unconventional sandstone cores to determine the test cores; The test cores were cleaned continuously for 10 days using benzene and petroleum ether in a ratio of 3:1 at 5 MPa and 80°C; The cleaned test core was placed in an 80°C constant temperature box for 24 hours for drying; After drying, the test core is cut and polished to produce core samples of unconventional sandstone standard plungers with a preset length and a preset diameter.

6. The method according to claim 1, wherein The core samples include core samples 1, 2 and 3. The core samples were subjected to water saturation experiments, including: The mixed solution of actual formation water and manganese water was driven into the core depth at a temperature of 70°C, a displacement rate of 0.10 mL / min, and a displacement pressure of 15 MPa; When the liquid content of the outlet output fluid reaches 10PV during the displacement process, the displacement is stopped and the original formation water distribution model of the core sample is obtained.

7. The method according to claim 6, wherein Unconventional sandstone standard plunger core samples include core samples 1, 2, and 3. Oil saturation tests were conducted on the core samples, specifically including: After simulating the original formation water distribution, the simulated oil sample was displaced to the core depth at a temperature of 70°C, a displacement rate of 0.10 mL / min, and a displacement pressure of 18 MPa; When the liquid content of the output fluid at the outlet reaches 10PV during the displacement process, the displacement is stopped; Nuclear magnetic resonance on core samples T 2 spectrum sampling to establish the original formation oil and water distribution model of the core sample.

8. The method according to claim 1, wherein The core samples include core samples 1, 2 and 3. Water flooding experiments were conducted on the unconventional sandstone core samples used to establish the original formation oil-water distribution model, and the water flooding stage was obtained. T 2 Spectrum area value and water flooding stage T 2 spectrum, specifically including: The actual formation water was displaced deep into the core at a temperature of 70°C and a displacement rate of 0.10 mL / min; The displacement pressures of core samples No. 1, No. 2, and No. 3 were set to 8 MPa, 15 MPa, and 22 MPa, respectively. The confining pressure pump was used to set the confining pressures of core samples No. 1, No. 2, and No. 3 to 10 MPa, 17 MPa, and 24 MPa, respectively. When the water content of the output fluid from outlets 1, 2, and 3 of core samples is above 98%, the displacement is stopped; Conduct water flooding experiments using NMR T 2 spectrum sampling, to obtain the water flooding stage T 2 Spectrum area value and water flooding stage T 2 scores.

9. The method according to claim 1, wherein The core samples include core samples 1, 2 and 3. The core samples were subjected to gas drive experiments to obtain the gas drive stage. T 2 Spectral area value and gas flooding stage T 2 spectrum, specifically including: The temperature was set to a constant 70°C and the displacement rate to 0.10 mL / min; The CO2 injection pressures of core samples 1, 2, and 3 were set to 8 MPa, 15 MPa, and 22 MPa, respectively, using a high-pressure, high-precision plunger pump. The confining pressures of core samples 1, 2, and 3 were set to 10 MPa, 17 MPa, and 24 MPa, respectively, using a confining pressure pump. Physical flow simulation experiments of CO2 flooding were conducted on core samples 1, 2, and 3, with CO2 in supercritical, near-miscible, and miscible states, respectively. Displacement was stopped at each stage when the quality of the output fluid at the outlet no longer changed. Nuclear magnetic resonance after multiphase CO2 flooding T 2 spectrum sampling, to obtain the gas drive stage T 2 Spectral area value and gas flooding stage T 2 scores.

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