Method for predicting imbibition volume of shale oil fracturing fluid

Abstract

The invention discloses a method for predicting the imbibition volume of shale oil fracturing fluid, which comprises the following steps of: 1, processing an underground rock sample of a shale oil reservoir section or outcrop rock at the same position into a standard rock core, testing a micro-pore structure of the standard rock sample, acquiring pore parameters of the standard rock core, and testing a wetting contact angle; 2, a spontaneous imbibition experiment of the standard rock core is carried out, and the scale imbibition area of the mine field is calculated; and step 3, establishing a multi-scale pore imbibition model based on the rock micro-pore structure and the characteristic parameters obtained by the spontaneous imbibition experiment, and calculating the imbibition volume through the multi-scale pore imbibition model. According to the method, shale oil horizontal well volume fracturing imbibition volume quantitative calculation can be achieved.

Description

Technical Field

[0001] The invention belongs to the technical field of petroleum and natural gas engineering, and in particular relates to a method for predicting the imbibition volume of shale oil fracturing fluid. Background Art

[0002] China has abundant shale oil resources, with technically recoverable resources of 145×10 8 t, has become the most strategic oil replacement resource. Horizontal well segmented multi-cluster volume fracturing is a key technology for the efficient development of shale oil and gas. Unlike conventional oil reservoirs, unconventional shale oil and gas reservoirs usually develop multi-scale micro-nano pores. Oil-water imbibition displacement after volume fracturing is an important mechanism for the development of unconventional resources. Fracturing fluid is imbibed into the reservoir under multiple forces such as capillary pressure and fluid pressure. On the one hand, it displaces oil and gas to the wellbore and produces on the ground, and on the other hand, it replenishes energy for the formation. Among them, the imbibition wave and volume of fracturing fluid in the reservoir is an important indicator that directly characterizes the production capacity and stable production capacity of later production wells. It is also a difficult problem that urgently needs to be solved to guide whether the well needs to be blocked and the blocking time after the current shale oil and gas volume fracturing. However, the migration and distribution laws of fracturing fluid in shale oil multi-scale micro-nano pores are extremely complex, and the quantitative characterization of imbibition volume brings great challenges. At present, domestic and foreign scholars have done a lot of research on the calculation of fracture network imbibition wave and volume, mainly the following:

[0003] (1) Zhao Yulong et al. (Zhao Yulong, Liu Xiangyu, Zhang Liehui et al. An experimental device and experimental method for evaluating the imbibition depth of fracturing fluid in high-temperature and high-pressure tight oil reservoirs, patent number: CN202111112528.4) This method builds a physical simulation experiment to simulate the contact between the fracturing fluid and the reservoir matrix at the fracture surface under formation conditions, and monitors the imbibition distance of the fracturing fluid at different times in real time based on the resistivity test, so as to obtain the law of change of the imbibition depth of the fracturing fluid during the well soaking process.

[0004] (2) Liu Jin et al. (Liu Jin, Xue Xiaojia, Li Kai et al. A dense core imbibition experimental device and imbibition test method, patent number: CN201711239406.5) The test device of this method includes an injection unit, a core chamber and a metering unit. The imbibition process under reservoir temperature and pressure conditions is carried out, and the change of imbibition amount at different times with time is recorded by using a precise measuring device, so as to achieve quantitative characterization of the imbibition amount.

[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 imbibition and time in porous media, patent number: CN202110265631.6). This method selects two rock samples of predetermined sizes for cleaning and drying, first evacuates the first rock sample and then injects water to form a saturated sample, which is then centrifuged to obtain nuclear magnetic resonance saturated and centrifugal T2 spectra; then, the second rock sample is used to carry out a spontaneous imbibition experiment, and the nuclear magnetic resonance is used to continuously obtain the T2 spectrum of the pore distribution during the imbibition process; the imbibition permeability, average capillary pressure and surface relaxation rate of the rock sample are calculated based on the data of the above 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 imbibition and time in the spontaneous imbibition process of porous media based on the principle of nuclear magnetic resonance.

[0006] In summary, methods (1) and (2) develop a core spontaneous device to carry out the imbibition test experiment under reservoir temperature and pressure conditions. This method can quantitatively characterize the core at the experimental scale, but it cannot calculate the imbibition after volume fracturing at the mine scale, which is the most concerned. At the same time, due to the influence of the core size, the experiment cannot truly reflect the actual imbibition of the fracture surface in the mine. Method (3) quantitatively characterizes the imbibition by establishing a porous medium imbibition model, but it also cannot obtain the imbibition at the mine scale, and it is difficult to guide the optimization of the mine well blocking system. At the same time, the three methods do not consider the importance of the net pressure of the fluid in the fracture after fracturing of shale oil horizontal wells to the imbibition. Therefore, it is necessary to propose a new quantitative calculation method suitable for shale oil porous media pore volume fracturing that simultaneously considers the fluid pressure and the mine scale imbibition volume, which provides strong support for the optimization of the well blocking system after volume fracturing of unconventional shale oil and the deepening of the understanding of the porous medium imbibition mechanism. Summary of the invention

[0007] The purpose of the present invention is to provide a method for predicting the imbibition volume of shale oil fracturing fluid, so as to solve the problems that the existing prediction methods are unable to calculate the imbibition volume after volume fracturing at the mine scale of greatest concern, are unable to truly reflect the imbibition volume of the actual mine fracture surface, and do not consider the importance of the net pressure of the fluid in the fracture after fracturing of shale oil horizontal wells to the imbibition volume.

[0008] In order to achieve the above object, the technical solution adopted by the present invention is: a method for predicting the imbibition volume of shale oil fracturing fluid, which is specifically implemented according to the following steps:

[0009] Step 1: Processing downhole rock samples of shale oil reservoir sections or outcrop rocks at the same layer into standard cores, testing the microscopic pore structure of the standard rock samples, obtaining pore parameters of the standard cores and conducting wetting contact angle tests;

[0010] Step 2: Conduct spontaneous imbibition experiments on standard cores and calculate the field-scale imbibition area;

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

[0012] As a preferred technical solution of the present invention, in step 1, processing the downhole rock sample of the shale oil reservoir section or the outcrop rock at the same layer into a standard core is specifically as follows:

[0013] Step 1.1, obtain the downhole core of the reservoir where the evaluation horizontal well is located or the horizontal well in the same layer of the same block, and make the rock of the reservoir section into a standard rock sample with a diameter of 2.5 cm and a length of 5 cm. Place the standard rock sample in a 100°C oven and dry it to constant weight.

[0014] As a preferred technical solution of the present invention, in step 1, the microscopic pore structure of the standard rock sample is tested, and the pore parameters of the standard core are obtained as follows:

[0015] Step 1.2, using nitrogen adsorption method to test the microscopic pore structure of the standard rock sample and obtain the main distribution pore diameter of the standard rock sample.

[0016] As a preferred technical solution of the present invention, in step 1, the wetting contact angle test is carried out as follows:

[0017] Step 1.3, use a video optical contact angle meter to test and collect the distribution image of the droplet on the surface of the standard rock sample to evaluate the wettability of the standard rock sample. The specific operation is to test the contact angles 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, step 2, a spontaneous imbibition experiment of a standard core is carried out to calculate the field-scale imbibition area as follows:

[0019] Step 2.1, using the weighing method to measure the liquid self-imbibition at different times, establish an imbibition model of imbibition amount and time, the expression is shown in (1);

[0020]

[0021] Where: V is the imbibition volume, m 3 ; A is the crack area, m 2 ; t is the imbibition time, min; b and c are coefficients, dimensionless;

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

[0023] y=kx+d (2)

[0025] b=10 d (3)

[0027] c=k (4)

[0029] Step 2.3, by substituting formula (3) and (4) into formula (1), the total fracture imbibition area of ​​the entire well section of the horizontal well volume fracturing is further obtained, and the calculation formula is shown in (5), where the imbibition volume V is equal to the total fracturing fluid volume of the horizontal well volume fracturing;

[0030]

[0031] Where: A is the total fracture imbibition area of ​​the entire well section of the horizontal well.

[0032] As a preferred technical solution of the present invention, step 3 is to establish a multi-scale pore imbibition model based on the rock microscopic pore structure and characteristic parameters obtained from spontaneous imbibition experiments, specifically:

[0033] Step 3.1, using a porosity meter with helium as the working medium to test the porosity of the standard core obtained in step 1 is

[0034] Step 3.2, calculate the imbibition dynamic fluid pressure of the fracturing fluid according to the original formation pressure of the reservoir and the formation pressure after volume fracturing. The expression is as follows:

[0035] P=P p -P o (6)

[0037] Step 3.3, based on the basic parameters measured by the rock sample in step 1), a multi-scale pore imbibition model is established, and the expression is as follows:

[0038]

[0039] As a preferred technical solution of the present invention, step 3, calculating the imbibition volume by a multi-scale pore imbibition model, specifically:

[0040] Step 3.4, substitute formula (5) and formula (6) into formula (7) to obtain the multi-scale pore imbibition volume calculation formula as follows:

[0041]

[0042] The beneficial effects of the present invention are as follows: (1) The present invention proposes a method for predicting the imbibition volume of shale oil fracturing fluid, which effectively solves the current problem of quantitatively characterizing the imbibition volume of fracturing fluid in horizontal well volume fracturing transformation of unconventional reservoirs in the field-scale fracture network; (2) The present invention provides a method for predicting the imbibition volume of shale oil fracturing fluid. Compared with the previous method of characterizing the imbibition volume of fracturing fluid by experiments or numerical simulations, which only stays at the experimental scale, the calculation method and accuracy are greatly improved. At the same time, compared with the current mine field obtaining the imbibition transformation volume through microseismic monitoring, this method greatly saves the testing cost, and its calculation method is simple and feasible, with strong operability, and is also applicable to the calculation of the imbibition volume of fracturing fluid in other unconventional reservoirs, providing reliable support for the improvement and optimization of volume fracturing technology. BRIEF DESCRIPTION OF THE DRAWINGS

[0043] Figure 1 It is a principle diagram of a method for predicting the imbibition volume of shale oil fracturing fluid of the present invention;

[0044] Figure 2 It is a double logarithmic curve of the permeation amount of fracturing fluid per unit area and the permeation time in a method for predicting the permeation volume of shale oil fracturing fluid of the present invention. DETAILED DESCRIPTION

[0045] The present invention is further described in detail below in conjunction with the accompanying drawings, tables and specific embodiments. The specific embodiments described herein are only used to explain the present invention and are not used to limit the present invention.

[0046] The present invention is further described below by way of examples, but is not limited to the following embodiments.

[0047] Example 1

[0048] A shale oil horizontal well H-1 adopts volume fracturing transformation, with a horizontal section length of 1920m, an oil layer drilling rate of 85.0%, a total of 24 fracturing sections, and a total fracturing fluid volume of 32740m3, which illustrates the specific implementation process of the present invention.

[0049] like Figure 1 As shown, a method for predicting the imbibition volume of shale oil fracturing fluid of the present invention is specifically implemented according to the following steps:

[0050] Step 1: Processing downhole rock samples of shale oil reservoir sections or outcrop rocks at the same layer into standard cores, testing the microscopic pore structure of the standard rock samples, obtaining pore parameters of the standard cores and conducting wetting contact angle tests;

[0051] Step 2: Conduct spontaneous imbibition experiments on standard cores and calculate the field-scale imbibition area;

[0052] Step 3: A multi-scale pore imbibition model is established based on the rock microscopic pore structure and characteristic parameters obtained from spontaneous imbibition experiments. The imbibition volume is calculated through the multi-scale pore imbibition model. The larger the imbibition volume, the better the volume fracturing effect.

[0053] Combination Figure 2 The present invention provides a method for predicting the imbibition volume of shale oil fracturing fluid. First, downhole rock samples of the shale oil reservoir section or outcrop rocks at the same layer are processed into standard cores, the microscopic pore structure of the rock is tested, the pore parameters of the standard cores are obtained, and the wetting contact angle test is carried out. Secondly, a spontaneous imbibition experiment of the standard core is carried out to calculate the field-scale imbibition area. Finally, a multi-scale pore imbibition model is established based on characteristic parameters such as the microscopic pore structure of the rock and the spontaneous imbibition experiment, and the imbibition volume is calculated. The larger the value, the better the volume fracturing transformation effect, thereby achieving the purpose of quantitative calculation of the volume fracturing imbibition volume of shale oil horizontal wells.

[0054] Example 2

[0055] like Figure 1 As shown, different from Example 1, in the method for predicting the imbibition volume of shale oil fracturing fluid of the present invention, step 1 is to process the downhole rock sample of the shale oil reservoir section or the outcrop rock of the same layer into a standard core, test the microscopic pore structure of the standard rock sample, obtain the pore parameters of the standard core and carry out the wetting contact angle test, specifically:

[0056] Step 1.1, obtain the downhole core of the reservoir of the evaluation horizontal well H1-1, 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°C oven to dry to constant weight;

[0057] Step 1.2, using nitrogen adsorption method to test the microscopic pore structure of rock sample S1, obtaining that the main distributed pore diameter of rock sample S1 is 3.0 μm;

[0058] Step 1.3, use a video optical contact angle meter to test and collect the distribution image of the droplet on the surface of rock sample S1 to evaluate the wettability of the rock sample. The wetting contact angles at different positions of the test rock sample are 70.5°, 73.5°, and 71.9°, respectively, with an average of 72.0°.

[0059] Example 3

[0060] like Figure 1 As shown, different from Example 1, in the method for predicting the imbibition volume of shale oil fracturing fluid of the present invention, step 2 is to carry out a spontaneous imbibition experiment of a standard core and calculate the field-scale imbibition area, specifically:

[0061] Step 2.1: Use the weighing method to measure the fracturing fluid imbibition at different times. According to the experimental data, use formula (1) to make a double logarithmic curve of the imbibition per unit area and the imbibition time. See the attached figure. Figure 1 The curve is fitted with a linear function, and the linear function expression is y = 0.4407x-1.743, where k is 0.4407 and d is -0.1743. The coefficients b and c are further calculated using formulas (3) and (4) to be 0.018 and 0.4407, respectively.

[0062] Step 2.2, according to the total fracturing fluid volume V of horizontal well H-1 is 32740m 3 The total fracture imbibition area A of the entire well section of the horizontal well volume fracturing is calculated using formula (5) as 1.625×10 5 m 2 .

[0063] Example 4

[0064] like Figure 1 As shown, different from Example 1, in the method for predicting the imbibition volume of shale oil fracturing fluid of the present invention, a multi-scale pore imbibition model is established based on the characteristic parameters obtained from the rock microscopic pore structure and the spontaneous imbibition experiment, and the imbibition volume is calculated by the multi-scale pore imbibition model, specifically:

[0065] Step 3.1: Use a porosity meter with helium as the working medium to test the porosity of the rock sample S1 in step 1). 8.7%;

[0066] Step 3.2: According to the volume fracturing formation pressure P p is 22.6MPa, and the original formation pressure P o It is 15.8MPa, and the imbibition dynamic fluid pressure is calculated by formula (6) to be 6.8MPa.

[0067] Step 3.3, based on the basic data of steps 3.1 and 3.2 and the model calculation parameters (Table 1), the imbibition volume V of the fracturing fluid in the multi-scale pores after volume fracturing of the shale oil horizontal well is calculated using formula (8): imb 4070m 3 .

[0068] Table 1 Basic parameters for imbibition wave and volume calculation

[0069] parameter Numeric parameter Numeric 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 Imbibition time (min) 14400 .

Claims

1. A method for predicting the imbibition volume of shale oil fracturing fluid, characterized in that: Follow the steps below to implement it: Step 1: Processing downhole rock samples of shale oil reservoir sections or outcrop rocks at the same layer into standard cores, testing the microscopic pore structure of the standard rock samples, obtaining pore parameters of the standard cores and conducting wetting contact angle tests; Step 2: Conduct spontaneous imbibition experiments on standard cores and calculate the field-scale imbibition area; Step 3: Establish a multi-scale pore imbibition model based on the rock microscopic pore structure and characteristic parameters obtained from spontaneous imbibition experiments, and calculate the imbibition volume through the multi-scale pore imbibition model.

2. The method for predicting the imbibition volume of shale oil fracturing fluid according to claim 1, characterized in that: In step 1, processing the downhole rock sample of the shale oil reservoir section or the outcrop rock at the same layer into a standard core is specifically as follows: Step 1.1, obtain the downhole core of the reservoir where the evaluation horizontal well is located or the horizontal well in the same layer of the same block, and make the rock of the reservoir section into a standard rock sample with a diameter of 2.5 cm and a length of 5 cm. Place the standard rock sample in a 100°C oven and dry it to constant weight.

3. The method for predicting the imbibition volume of shale oil fracturing fluid according to claim 2, characterized in that: In step 1, the microscopic pore structure of the standard rock sample is tested, and the pore parameters of the standard core are obtained as follows: Step 1.2, using nitrogen adsorption method to test the microscopic pore structure of the standard rock sample and obtain the main distribution pore diameter of the standard rock sample.

4. The method for predicting the imbibition volume of shale oil fracturing fluid according to claim 3, characterized in that: In step 1, the wetting contact angle test is carried out as follows: Step 1.3, use a video optical contact angle meter to test and collect the distribution image of the droplet on the surface of the standard rock sample to evaluate the wettability of the standard rock sample. The specific operation is to test the contact angles 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 imbibition volume of shale oil fracturing fluid according to claim 4, characterized in that: In step 2, the spontaneous imbibition experiment of the standard core is carried out, and the mine-scale imbibition area is calculated as follows: Step 2.1, using the weighing method to measure the liquid self-imbibition at different times, establish an imbibition model of imbibition amount and time, the expression is shown in (1); Where: V is the imbibition volume, m 3 ; A is the crack area, m 2 ; t is the imbibition time, min; b and c are coefficients, dimensionless; Step 2.2, according to the experimental data, use formula (1) to make a double logarithmic curve of the permeation amount per unit area and the permeation time, and fit the curve with a linear function to obtain a linear function expression (2). Further, the coefficients b and c in formula (1) are obtained according to the linear function. The calculation formula is as follows: y=kx+d (2) b＝10 d (3) c=k (4) Step 2.3, by substituting formula (3) and (4) into formula (1), the total fracture imbibition area of ​​the entire well section of the horizontal well volume fracturing is further obtained, and the calculation formula is shown in (5), where the imbibition volume V is equal to the total fracturing fluid volume of the horizontal well volume fracturing; Where: A is the total fracture imbibition area of ​​the entire well section of the horizontal well.

6. The method for predicting the imbibition volume of shale oil fracturing fluid according to claim 5, characterized in that: Step 3: Establish a multi-scale pore imbibition model based on the rock microscopic pore structure and characteristic parameters obtained from spontaneous imbibition experiments, specifically: Step 3.1, using a porosity meter with helium as the working medium to test the porosity of the standard core obtained in step 1 is Step 3.2, calculate the imbibition dynamic fluid pressure of the fracturing fluid according to the original formation pressure of the reservoir and the formation pressure after volume fracturing. The expression is as follows: P=P p -P o (6) Step 3.3, based on the basic parameters measured by the rock sample in step 1), a multi-scale pore imbibition model is established, and the expression is as follows: (7)。 7. The method for predicting the imbibition volume of shale oil fracturing fluid according to claim 6, characterized in that: Step 3: Calculate the imbibition volume using a multi-scale pore imbibition model, specifically: Step 3.4, substitute formula (5) and formula (6) into formula (7) to obtain the multi-scale pore imbibition volume calculation formula as follows:

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