Methods for predicting the volume of fracturing fluid absorbed in shale oil

Abstract

This invention discloses a method for predicting the volume of fracturing fluid in shale oil, comprising the following steps: Step 1, processing downhole rock samples or outcrops from the same stratum of the shale oil reservoir into standard cores, testing the microstructure of the standard rock samples, obtaining the pore parameters of the standard cores, and conducting wetting contact angle tests; Step 2, conducting spontaneous absorption experiments on the standard cores and calculating the field-scale absorption area; Step 3, establishing a multi-scale pore absorption model based on the rock microstructure and the characteristic parameters obtained from the spontaneous absorption experiments, and calculating the absorption volume using the multi-scale pore absorption model. This invention can achieve quantitative calculation of the volumetric fracturing absorption volume in shale oil horizontal wells.

Description

Technical Field

[0001] This invention belongs to the field of petroleum and natural gas engineering technology, specifically relating to a method for predicting the volume of fracturing fluid absorbed in shale oil. Background Technology

[0002] China has abundant shale oil resources, with technically recoverable resources estimated at 145 × 10⁻⁶. 8 Shale oil and gas has become the most strategic alternative resource for petroleum. Horizontal well segmented multi-cluster volumetric fracturing is a key technology for the efficient development of shale oil and gas. Unlike conventional reservoirs, unconventional shale oil and gas reservoirs typically develop multi-scale micro- and nano-pores. Oil-water percolation and replacement after volumetric fracturing is a crucial mechanism in the development of unconventional resources. Under the combined forces of capillary pressure and fluid pressure, fracturing fluid percolates into the reservoir, replacing oil and gas flow into the wellbore for production at the surface, and simultaneously replenishing the formation with energy. The percolation sweep volume of fracturing fluid in the reservoir is a crucial indicator directly representing the production capacity and stability of later-stage production wells, and it is also a pressing problem that needs to be solved to guide whether well shut-in is necessary and for how long after volumetric fracturing in shale oil and gas. However, the migration and distribution patterns of fracturing fluid in the multi-scale micro- and nano-pores of shale oil are extremely complex, posing a significant challenge to the quantitative characterization of percolation volume. Currently, scholars both domestically and internationally have conducted extensive research on the calculation of percolation sweep volume in fracture networks, mainly including the following methods:

[0003] (1) Zhao Yulong et al. (Zhao Yulong, Liu Xiangyu, Zhang Liehui et al. An experimental device and method for evaluating the penetration depth of fracturing fluid in high-temperature and high-pressure tight oil reservoirs, patent number: CN202111112528.4) This method simulates the contact between fracturing fluid and reservoir matrix at the fracture surface under formation conditions by building a physical simulation experiment. Based on resistivity testing, the penetration distance of fracturing fluid at different times is monitored in real time, thereby obtaining the variation law of fracturing fluid penetration depth during the well simmering process.

[0004] (2) Liu Jin et al. (Liu Jin, Xue Xiaojia, Li Kai et al. A dense core permeation test device and permeation measurement method, patent number: CN201711239406.5) The test device of this method includes an injection unit, a core chamber and a metering unit. By carrying out the permeation process under reservoir temperature and pressure conditions, and using a precise measuring device to record the change of permeation amount over time at different times, the quantitative characterization of permeation amount is achieved.

[0005] (3) Yao Yanbin et al. (Yao Yanbin, Li Zishuo, Liu Dameng et al. A method for establishing a mathematical model of the relationship between spontaneous permeation and time in porous media, patent number: CN202110265631.6). This method selects two rock samples of a predetermined size, cleans and dries them. The first rock sample is first vacuumed and then water is injected to form a saturated sample. It is then centrifuged to obtain the T2 spectrum of saturated and centrifuged samples by nuclear magnetic resonance. Then, the second rock sample is used to carry out spontaneous permeation experiments, and the T2 spectrum of pore distribution during the permeation process is continuously obtained by nuclear magnetic resonance. The permeability, average capillary pressure and surface relaxation rate of the rock sample are calculated based on the data of the two rock samples. The obtained parameters are substituted into the Handy equation and the corresponding parameters are replaced to obtain a mathematical model of the relationship between permeation and time in the spontaneous permeation process of porous media based on the principle of nuclear magnetic resonance.

[0006] In summary, methods (1) and (2) utilize a core-based self-generating device to conduct permeation tests under reservoir temperature and pressure conditions. While this approach can quantitatively characterize core data at the experimental scale, it cannot calculate permeation after volumetric fracturing at the most critical field scale. Furthermore, the experiments are affected by the core size, failing to accurately reflect the actual permeation at the fracture surface in the field. Method (3) quantitatively characterizes permeation by establishing a porous media permeation model, but it also cannot obtain permeation at the field scale, making it difficult to guide the optimization of the field shut-in system. Moreover, none of the three methods consider the importance of net fluid pressure within the fractured area after shale oil horizontal well fracturing to permeation. Therefore, it is necessary to propose a new quantitative calculation method suitable for shale oil porous media volumetric fracturing that simultaneously considers fluid pressure and field-scale permeation volume, providing strong support for optimizing the shut-in system after unconventional shale oil volumetric fracturing and deepening the understanding of porous media permeation mechanisms. Summary of the Invention

[0007] The purpose of this invention is to provide a method for predicting the volume of fracturing fluid in shale oil, which solves the problems of existing prediction methods, such as the inability to calculate the volumetric fracturing volume after fracturing at the most important field scale, the inability to accurately reflect the actual fracturing volume at the fracture surface, and the failure to consider the importance of the net fluid pressure within the fracture after fracturing in shale oil horizontal wells to the volume of fluid absorbed.

[0008] To achieve the above objectives, the technical solution adopted in this invention is: a method for predicting the volume of fracturing fluid absorption in shale oil, specifically implemented according to the following steps:

[0009] Step 1: Process downhole rock samples or outcrops of the same stratum from the shale oil reservoir into standard cores, test the microstructure of the standard rock samples, obtain the pore parameters of the standard cores, and conduct wetting contact angle tests.

[0010] Step 2: Conduct spontaneous percolation experiments on standard core samples and calculate the percolation area at the mine scale;

[0011] Step 3: Establish a multi-scale pore permeation model based on the characteristic parameters obtained from the rock micropore structure and spontaneous permeation experiments, and calculate the permeation volume through the multi-scale pore permeation model.

[0012] As a preferred technical solution of the present invention, in step 1, processing the downhole rock samples or outcrops of the same stratum in the shale oil reservoir section into standard cores specifically involves:

[0013] Step 1.1: Obtain the downhole core of the horizontal well in the reservoir or the same layer of the same block. Make standard rock samples with a diameter of 2.5 cm and a length of 5 cm from the rock in the reservoir section. Place the standard rock samples in a 100℃ oven and dry them to constant weight.

[0014] As a preferred technical solution of the present invention, in step 1, testing the micropore structure of the standard rock sample and obtaining the pore parameters of the standard rock core specifically involves:

[0015] Step 1.2: Use nitrogen adsorption method to test the micropore structure of standard rock samples and obtain the diameter of the main distributed pores in the standard rock samples.

[0016] As a preferred embodiment of the present invention, in step 1, the wetting contact angle test is specifically performed as follows:

[0017] Step 1.3: Use a video optical contact angle meter to test and collect images of the droplet distribution on the surface of a standard rock sample to evaluate the wettability of the standard rock sample. Specifically, test the contact angle at different positions on the surface of the rock sample and take the average value as the wetting contact angle of the sample.

[0018] As a preferred technical solution of the present invention, in step 2, the spontaneous percolation experiment of the standard core is carried out to calculate the percolation area at the mine scale, specifically as follows:

[0019] Step 2.1: Measure the self-absorption of liquid at different times using the weighing method, and establish an absorptive model of the absorptive amount versus time, as shown in (1).

[0020]

[0021] In the formula: V is the osmotic volume, m 3 A is the crack area, in meters. 2 t is the absorption time, in minutes; b and c are coefficients, dimensionless.

[0022] Step 2.2: Based on the experimental data, use formula (1) to plot a double logarithmic curve of permeation amount per unit area versus permeation time, and fit the curve to a linear function to obtain the linear function expression (2). Further, use the linear function to calculate the coefficients b and c in formula (1). The calculation formula is as follows:

[0023] y=kx+d (2)

[0024] b = 10 d (3)

[0025] c = k (4)

[0026] Step 2.3, by substituting formulas (3) and (4) into formula (1), the total area of ​​fractures in the entire horizontal well section under volumetric fracturing is further obtained. The calculation formula is shown in (5), where the volume of permeation V is equal to the total fracturing fluid volume of the horizontal well under volumetric fracturing.

[0027]

[0028] In the formula: A is the total fracture permeation area of ​​the entire horizontal well section.

[0029] As a preferred technical solution of the present invention, step 3, establishing a multi-scale pore permeation model based on the characteristic parameters obtained from the rock micropore structure and spontaneous permeation experiments, specifically involves:

[0030] Step 3.1: Using a porosimeter with helium as the working medium, test the porosity of the standard core obtained in Step 1.

[0031] Step 3.2: Based on the original formation pressure and the formation pressure after volumetric fracturing, calculate the fracturing fluid adsorption dynamic pressure, as shown in the following expression:

[0032] P = P p -P o (6)

[0033] Step 3.3: Based on the basic parameters measured in the rock sample from Step 1), establish a multi-scale porosity permeability model, expressed as follows:

[0034]

[0035] As a preferred technical solution of the present invention, step 3, calculating the permeation volume using a multi-scale pore permeation model, specifically involves:

[0036] Step 3.4, Substitute formulas (5) and (6) into formula (7) to obtain the following formula for calculating the multi-scale pore adsorption volume:

[0037]

[0038] The beneficial effects of this invention are: (1) This invention proposes a method for predicting the volume of fracturing fluid in shale oil, which effectively solves the problem of quantitative characterization of the volume of fracturing fluid in unconventional reservoir horizontal wells at the field scale fracture network; (2) This invention's method for predicting the volume of fracturing fluid in shale oil is significantly improved in terms of calculation method and accuracy compared to previous methods that only characterized the volume of fracturing fluid through experiments or numerical simulations at the experimental scale. Furthermore, compared to the current method of obtaining the volume of fracturing fluid through microseismic monitoring at the field, this method greatly saves testing costs. Its calculation method is simple, feasible, and highly operable, and it is also applicable to the calculation of the volume of fracturing fluid in other unconventional reservoirs, providing reliable support for the improvement and optimization of volumetric fracturing technology. Attached Figure Description

[0039] Figure 1 This is a schematic diagram of a method for predicting the volume of fracturing fluid in shale oil according to the present invention.

[0040] Figure 2 This invention relates to a method for predicting the volume of fracturing fluid absorbed by shale oil, which uses a double logarithmic curve of fracturing fluid absorption per unit area versus absorption time. Detailed Implementation

[0041] The present invention will be further described in detail below with reference to the accompanying drawings and specific embodiments. The specific embodiments described herein are only used to explain the present invention and are not intended to limit the present invention.

[0042] The present invention is further described below through embodiments, but is not limited to the following implementation examples.

[0043] Example 1

[0044] A shale oil horizontal well, H-1, was subjected to volumetric fracturing. The horizontal section was 1920m long, the oil layer penetration rate was 85.0%, a total of 24 fracturing stages were completed, and the total fracturing fluid volume was 32740m3. This paper describes the specific implementation process of the present invention.

[0045] like Figure 1 As shown, the method for predicting the volume of fracturing fluid in shale oil according to the present invention is implemented according to the following steps:

[0046] Step 1: Process downhole rock samples or outcrops of the same stratum from the shale oil reservoir into standard cores, test the microstructure of the standard rock samples, obtain the pore parameters of the standard cores, and conduct wetting contact angle tests.

[0047] Step 2: Conduct spontaneous percolation experiments on standard core samples and calculate the percolation area at the mine scale;

[0048] Step 3: Establish a multi-scale pore permeation model based on the characteristic parameters obtained from the rock micropore structure and spontaneous permeation experiments. Calculate the permeation volume using the multi-scale pore permeation model. The larger the value, the better the volumetric fracturing effect.

[0049] Combination Figure 2 This invention discloses a method for predicting the volume of fracturing fluid in shale oil. First, downhole rock samples or outcrops from the same stratum of the shale oil reservoir are processed into standard cores. The microscopic pore structure of the rock is tested to obtain the pore parameters of the standard cores, and wetting contact angle tests are conducted. Second, spontaneous absorption experiments are performed on the standard cores to calculate the field-scale absorption area. Finally, based on the characteristic parameters such as the rock microscopic pore structure and spontaneous absorption experiments, a multi-scale pore absorption model is established to calculate the absorption volume. The larger the value, the better the volumetric fracturing effect, thereby achieving the goal of quantitatively calculating the volumetric fracturing absorption volume of shale oil horizontal wells.

[0050] Example 2

[0051] like Figure 1 As shown, unlike Example 1, in the method for predicting the volume of fracturing fluid in shale oil according to the present invention, step 1 involves processing downhole rock samples or outcrops of the same stratum in the shale oil reservoir section into standard cores, testing the microstructure of the standard rock samples, obtaining the pore parameters of the standard cores, and conducting wetting contact angle tests. Specifically:

[0052] Step 1.1: Obtain the downhole core of the H1-1 reservoir in the evaluation horizontal well. Process the core of the reservoir section into a standard rock sample S1 with a diameter of 2.5 cm and a length of 5 cm, and place the standard rock sample in a 100℃ oven to dry to constant weight.

[0053] Step 1.2: The microstructure of rock sample S1 was tested using the nitrogen adsorption method, and the diameter of the main pores in rock sample S1 was found to be 3.0 μm.

[0054] Step 1.3: Use a video optical contact angle meter to test and acquire images of the droplet distribution on the surface of rock sample S1 to evaluate the wettability of the rock sample. The wetting contact angles at different locations on the rock sample were 70.5°, 73.5°, and 71.9°, with an average value of 72.0°.

[0055] Example 3

[0056] like Figure 1 As shown, unlike Example 1, in the method for predicting the volume of fracturing fluid in shale oil according to the present invention, step 2, conducting spontaneous percolation experiments on standard core samples and calculating the field-scale percolation area, specifically involves:

[0057] Step 2.1: The amount of fracturing fluid absorbed at different times was measured by weighing. Based on the experimental data, a double logarithmic curve of the absorption per unit area versus absorption time was plotted using formula (1). (See Appendix) Figure 1 The curve is fitted with a linear function to obtain the linear function expression y = 0.4407x - 1.743, where k is 0.4407 and d is -0.1743. The coefficients b are calculated to be 0.018 and c is 0.4407 using formulas (3) and (4).

[0058] Step 2.2, based on the total fracturing fluid volume V of horizontal well H-1 being 32740m³ 3 Using formula (5), the total fracture permeation area A of the entire horizontal well section after volumetric fracturing is calculated to be 1.625 × 10⁻⁶. 5 m 2 .

[0059] Example 4

[0060] like Figure 1 As shown, unlike Example 1, in the shale oil fracturing fluid adsorption volume prediction method of the present invention, a multi-scale pore adsorption model is established based on the characteristic parameters obtained from the rock micropore structure and spontaneous adsorption experiments. The adsorption volume is calculated through the multi-scale pore adsorption model, specifically as follows:

[0061] Step 3.1 Use a porosimeter with helium as the working medium to test the porosity of rock sample S1 mentioned in step 1). It was 8.7%;

[0062] Step 3.2 Based on the formation pressure P after volumetric fracturing p The original formation pressure P is 22.6 MPa. o The pressure is 15.8 MPa. Using formula (6), the pressure of the seepage dynamic fluid is calculated to be 6.8 MPa.

[0063] Step 3.3: Based on the basic data from Steps 3.1 and 3.2, and the model calculation parameters (Table 1), calculate the volume V of fracturing fluid absorbed into the multi-scale pores after volumetric fracturing of a shale oil horizontal well using formula (8). imb 4070m 3 .

[0064] Table 1. Basic Parameters for Immersion Wave and Volume Calculation

[0065] parameter numerical values parameter numerical values Pore ​​diameter (μm) 3.0 Fracturing fluid viscosity (mPa.s) 2.0 Surface tension (mN / m) 35.0 Porosity (%) 8.7 Wetting contact angle (°) 72.0 Immersion time (min) 14400 .

Claims

1. A method for predicting the volume of fracturing fluid absorbed in shale oil, characterized in that, The specific steps are as follows: Step 1: Process downhole rock samples or outcrops of the same stratum from the shale oil reservoir into standard cores, test the microstructure of the standard rock samples, obtain the pore parameters of the standard cores, and conduct wetting contact angle tests. Step 2: Conduct spontaneous percolation experiments on standard core samples and calculate the percolation area at the mine scale. Specifically: Step 2.1: Measure the liquid absorption volume at different times using the weighing method, and establish an absorption model of absorption volume versus time, as shown in (1); （1） In the formula: This represents the volume of osmosis, in cubic meters (m³). 3 ; The total fracture area of ​​the horizontal well is measured in m². 2 ; This refers to the absorption time, expressed in minutes. b and c The coefficient is dimensionless; Step 2.2: Based on the experimental data, use formula (1) to plot a double logarithmic curve of permeation amount per unit area versus permeation time, and fit the curve to a linear function to obtain the linear function expression (2). Further, use the linear function to calculate the coefficients in formula (1). b and c， The calculation formula is as follows: （2） （3） （4） Step 2.3: Substituting formulas (3) and (4) into formula (1) further yields the total fracture permeation area of ​​the entire horizontal well section after volumetric fracturing. The calculation formula is shown in (5), where the permeation volume is... V Equal to the total fracturing fluid volume in horizontal well volumetric fracturing; （5） In the formula: The total fracture area of ​​the horizontal well is measured in m². 2 ; Step 3: Establish a multi-scale pore permeation model based on the characteristic parameters obtained from the rock micropore structure and spontaneous permeation experiments, and calculate the permeation volume through the multi-scale pore permeation model; Specifically, a multi-scale pore permeation model is established based on the characteristic parameters obtained from rock micropore structure and spontaneous permeation experiments. Step 3.1: Using a porosimeter with helium as the working medium, test the porosity of the standard core obtained in Step 1. ; Step 3.2, based on the original formation pressure of the reservoir Formation pressure after volumetric fracturing The dynamic fluid pressure for fracturing fluid absorption is calculated using the following expression: （6） Step 3.3: Based on the fundamental parameters measured in the rock sample from Step 1), establish a multi-scale porosity permeability model, expressed as follows: （7）； In the formula: This represents the total volume of fracturing fluid absorbed from a horizontal well, in cubic meters (m³). 3 ; The area of ​​seepage and absorption in the crack is expressed in m². 2 ; D The pore diameter of the rock sample is in meters. Porosity, expressed as % The viscosity of the permeated liquid is expressed in mPa·s. The surface tension of the absorbed liquid is expressed in mN / m. The wetting angle of the permeated liquid in the pores, expressed in degrees (°). This represents the formation pressure after volumetric fracturing, in MPa. This represents the original formation pressure, expressed in MPa. t This represents the absorption time, expressed in minutes.

2. The method for predicting the volume of fracturing fluid in shale oil according to claim 1, characterized in that, In step 1, the process of processing downhole rock samples or outcrops from the same stratum of the shale oil reservoir into standard cores specifically involves: Step 1.1: Obtain the downhole core of the horizontal well in the reservoir or the same layer of the same block. Make standard rock samples with a diameter of 2.5 cm and a length of 5 cm from the rock in the reservoir section. Place the standard rock samples in a 100°C oven to dry to constant weight.

3. The method for predicting the volume of fracturing fluid in shale oil according to claim 2, characterized in that, In step 1, the microstructure of the standard rock sample is tested to obtain the pore parameters of the standard rock core. Step 1.2: Use nitrogen adsorption method to test the micropore structure of standard rock samples and obtain the diameter of the main distributed pores in the standard rock samples.

4. The method for predicting the volume of fracturing fluid in shale oil according to claim 3, characterized in that, In step 1, the wetting contact angle test is specifically performed as follows: Step 1.3: Use a video optical contact angle meter to test and collect images of the droplet distribution on the surface of a standard rock sample to evaluate the wettability of the standard rock sample. Specifically, test the contact angle at different positions on the surface of the rock sample and take the average value as the wetting contact angle of the sample.

5. The method for predicting the volume of fracturing fluid in shale oil according to claim 4, characterized in that, Step 3: Calculate the percolation volume using a multi-scale pore percolation model, specifically as follows: Step 3.4, Substitute formulas (5) and (6) into formula (7) to obtain the following formula for calculating the total volume of multi-scale pore permeation: （8）； In the formula: This represents the total volume of fracturing fluid absorbed from a horizontal well, in cubic meters (m³). 3 ; V This represents the volume of osmosis, in cubic meters (m³). 3 ; The total fracture area of ​​the horizontal well is measured in m². 2 ; D The pore diameter of the rock sample is in meters. Porosity, expressed as % d and k These are the fitting coefficients, dimensionless; The viscosity of the permeated liquid is expressed in mPa·s. The surface tension of the absorbed liquid is expressed in mN / m. The wetting angle of the permeated liquid in the pores, expressed in degrees (°). This represents the formation pressure after volumetric fracturing, in MPa. This represents the original formation pressure, expressed in MPa. t This represents the absorption time, expressed in minutes.

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