Method for testing fracture flow capacity under shale oil core stress condition

Abstract

The invention provides a method for testing fracture flow capacity under a shale oil core stress condition. The method comprises the following steps: forming a fracture on a core; carrying out vacuumizing and high-pressure saturated oil treatment on the rock core subjected to fracture forming; according to the core crack type, a plurality of net effective stress points are increased by changing the displacement pressure difference and the confining pressure, and then core outlet end flow data are obtained; a copper foil is utilized to support the crack, different crack opening degrees are simulated, a plurality of net effective stress points are added, flow data of the outlet end of the core are obtained, and shale core flow capacity evaluation under the condition of different crack opening degrees is achieved; after different flowing pressure differences are selected to achieve stable flowing, corresponding flowing data are obtained, and the liquid-phase permeability of the fractured rock core is calculated according to a Darcy formula; and evaluating the flow capacity of the rock core according to result data, comprehensive stress conditions and fracture forms. According to the invention, different fracture forms can be simulated, so that the experimental research is more comprehensive, and a reference is provided for the crude oil flowing capacity of fractured reservoirs in shale oil development at present.

Description

Technical Field

[0001] The invention belongs to the field of oil and gas field development, and in particular relates to a method for testing the flow capacity of fractures under shale oil core stress conditions. Background Art

[0002] Existing research methods mainly use mathematical flow models of shale matrix rocks and corresponding physical simulation experiments to evaluate the flow capacity of shale matrix rocks, which are used in shale gas exploration and development and other fields. However, there are basically no indoor physical simulation experiments for shale oil and fractured shale cores. Summary of the invention

[0003] The embodiment of the present application provides a method for testing the fracture flow capacity of shale oil cores under stress conditions, artificially creating fractures in the cores so that the shale cores that cannot be subjected to conventional displacement experiments have a certain flow capacity, and can simulate different fracture morphologies to make experimental research more comprehensive.

[0004] In the first aspect, the embodiment of the present application provides a method for testing the fracture flow capacity of a shale oil core under stress conditions, including: S1, core fracture creation; S2, vacuuming and high-pressure oil saturation treatment of the core after fracture creation; S3, according to the type of core fractures, by changing the displacement pressure difference and the confining pressure, adding multiple net effective stress points, and then obtaining the flow data at the core outlet; S4, using copper foil to support the fracture, simulating different fracture openings, adding multiple net effective stress points, obtaining the flow data at the core outlet, and realizing the evaluation of the flow capacity of the shale core under conditions of different fracture openings; S5, after selecting different flow pressure differences to achieve stable flow, obtaining the corresponding flow data, and calculating the liquid permeability of the fractured core according to the Darcy formula; S6, based on the result data, comprehensively evaluating the stress conditions and fracture morphology, the core flow capacity.

[0005] The core fracture formation in step S1 includes using a fracture splitting tool to obtain a core having a curved fracture, a straight fracture, or a double fracture shape.

[0006] Among them, in step S2, a core with open bedding fractures is obtained by using an oil saturation process; and the dry core is vacuumed and subjected to high-pressure oil saturation treatment.

[0007] Among them, in step S3, under the same displacement pressure difference, multiple net effective pressure points are added; when the net effective pressure point remains unchanged, the displacement pressure difference is increased, and the core flow capacity is evaluated by liquid permeability measurement.

[0008] Wherein, step S4 includes using copper foil to support the core fracture surface so that the fracture has a corresponding opening and the fracture support area reaches more than 80%, calculating its liquid permeability and evaluating the core flow capacity.

[0009] Wherein, step S5 includes: comprehensively evaluating the flow capacity of the core under stress conditions according to the corresponding fracture morphology, aperture, displacement pressure difference, net effective stress, etc. of the core, and calculating the liquid permeability of the core using Darcy's formula as follows:

[0010]

[0011] Where: K l — rock liquid permeability;

[0012] μ—Fluid viscosity under test conditions;

[0013] L—rock sample length;

[0014] A—cross-sectional area of ​​rock sample;

[0015] p1—rock sample inlet pressure;

[0016] p2—rock sample outlet pressure;

[0017] Q—The volume of fluid passing through the rock sample per unit time.

[0018] Wherein, step S5 also includes: the core flow capacity increases with the increase of the displacement pressure inlet end, and the flow capacity curves of different fracture openings have different shapes.

[0019] Wherein, step S5 includes, under the conditions of unsupported fracture aperture and second thickness supported fracture aperture, the shale oil flow rate increases exponentially with the increase of inlet pressure, and the increasing equation is: y = ae bx ,

[0020] In the formula, the coefficient a of the exponential increasing equation is related to the effective stress. The larger the effective stress, the smaller the value of a. The exponential coefficient b is determined by the shape of the curve as the inlet pressure increases, that is, it decreases first and then increases.

[0021] Wherein, step S5 includes: under the condition of the first thickness supporting fracture opening, the shale oil flow rate increases logarithmically with the increase of the inlet pressure, and the increasing equation is: y=c ln(x)-d,

[0022] In the formula, the fitting coefficient c of the logarithmic increasing equation is related to the effective stress. As the effective stress increases, the fitting coefficient c decreases linearly; d is the correction coefficient of the equation, which is determined by the curve shape reflected by different inlet pressures under the same effective stress conditions.

[0023] Wherein, step S6 includes evaluating the reasonable flow pressure difference and effective stress through the permeability relationship curve of the core under different fracture apertures and flow pressure differences.

[0024] The method for testing the flow capacity of fractures of shale oil under core stress conditions in the embodiment of the present application has the following beneficial effects: it solves the current experimental scheme for testing the flow capacity of non-fractured shale oil in the laboratory, and can simulate different fracture morphologies, making the experimental research more comprehensive, and providing a reference for the flow capacity of crude oil in fractured reservoirs in the current shale oil development. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] Figure 1 This is a flow chart of a method for testing fracture flow capacity under shale oil core stress conditions in an embodiment of the present application;

[0026] Figure 2 Another schematic diagram of the flow process of the fracture flow capacity testing method of shale oil core stress conditions in the embodiment of the present application;

[0027] Figure 3 This is a schematic diagram of the experimental device of the present application embodiment;

[0028] Figure 4 This is a schematic diagram of the variation of the permeability of a single seam without supporting fluid with the net effective stress in the embodiment of the present application;

[0029] Figure 5 This is a schematic diagram of the variation of the permeability of double slits without supporting fluid with the net effective stress in the embodiment of the present application;

[0030] Figure 6 This is a schematic diagram of the variation of the permeability of a branch fracture without supporting fluid with the net effective stress in an embodiment of the present application;

[0031] Figure 7 This is a schematic diagram of the change of liquid permeability of a single slit with different crack openings with net effective stress in the embodiment of the present application;

[0032] Figure 8 This is a schematic diagram of the variation of liquid permeability of double slits with different crack openings with net effective stress in the embodiment of the present application;

[0033] Fig. 9 This is a schematic diagram of the change of liquid permeability of branch fractures with different crack openings as a function of net effective stress in an embodiment of the present application;

[0034] Fig.10 This is the relationship between flow rate and pressure under different confining pressures when the crack in the embodiment of the present application is unsupported;

[0035] Fig.11 The relationship between flow rate and pressure under different confining pressures at the first thickness crack support height in the embodiment of the present application;

[0036] Fig.12 The relationship between flow rate and pressure under different confining pressures at the second thickness crack support height in the embodiment of the present application;

[0037] Fig.13This is a schematic diagram of the change in permeability of a complex fracture core with effective stress in an embodiment of the present application. DETAILED DESCRIPTION

[0038] The present application is further described below in conjunction with the accompanying drawings and embodiments.

[0039] In the following introduction, the terms "first" and "second" are used for descriptive purposes only and should not be understood as indicating or implying relative importance. The following introduction provides multiple embodiments of the present invention, and different embodiments can be replaced or combined, so this application can also be considered to include all possible combinations of the same and / or different embodiments recorded. Therefore, if one embodiment includes features A, B, and C, and another embodiment includes features B and D, then this application should also be considered to include embodiments containing one or more of all other possible combinations of features A, B, C, and D, even though the embodiment may not be clearly recorded in the following text.

[0040] Embodiment 1

[0041] Since the confining pressure test point of the indoor physical simulation experiment is a pressure rising process, and the actual production formation pressure on site is a pressure falling process, there is basically no indoor physical simulation experiment for shale oil shale cores with fractures. The confining pressure test point of this experiment is designed as a pressure rising process, which can more effectively collect the oil production at the core outlet. When the flow rate is reduced to 0.015mL per hour, the core flow capacity is roughly considered to be 0, which solves the current laboratory experimental plan for testing the flow capacity of non-fractured shale oil.

[0042] like Figure 1 As shown, the fracture flow capacity testing method of shale oil core under stress conditions of the present application includes: step S1, core fracture creation; step S2, vacuuming and high-pressure saturated oil treatment of the fractured core; step S3, according to the core fracture type, by changing the displacement pressure difference and the confining pressure, adding multiple net effective stress points, and then obtaining the flow data of the core outlet; step S4, using copper foil to support the fracture, simulating different fracture openings, adding multiple net effective stress points, obtaining the flow data of the core outlet, and realizing the evaluation of the flow capacity of the shale core under different fracture opening conditions; step S5, after selecting different flow pressure differences to achieve stable flow, obtaining the corresponding flow data, and calculating the liquid permeability of the fractured core according to the Darcy formula; step S6, based on the result data, comprehensively evaluating the stress conditions and fracture morphology.

[0043] The present application relates to a method for testing the flow capacity of fractures in shale oil cores under stress conditions. Artificial fractures are created in the cores to give the shale cores, which are unable to undergo conventional displacement experiments, a certain flow capacity. Different fracture morphologies can also be simulated to make experimental research more comprehensive, and can provide a reference for the flow capacity of crude oil in fractured reservoirs in current shale oil development.

[0044] Embodiment 2

[0045] The present application discloses a method for testing the flow capacity of fractures under stress conditions of shale oil cores. The complex fractures in the cores conform to the characteristics of the fracture network produced during the actual fracturing process. The experiment designs multiple confining pressure points to simulate the actual flow capacity during the formation pressure drop process.

[0046] like Figure 2 As shown, Figure 2 This is a flow chart of the shale core flow capacity test method under different stress and complex fracture conditions based on Darcy's law. The experimental device is as follows: Figure 3 As shown, the experimental device includes: a constant pressure and constant speed pump 10, a piston container 11, a pressure gauge 12, a core holder 13, a hand pump 14, and a measuring cylinder 15.

[0047] The specific implementation steps of this application are as follows:

[0048] Step S1, using a splitting tool to obtain a core with curved seams, straight seams, and double seams; using an oil saturation process to obtain a core with open bedding seams; and performing vacuum and high-pressure oil saturation treatment on the dry core.

[0049] Step S2, such as Figure 4 , Figure 5 , Figure 6 As shown in the figure, under the same displacement pressure difference, multiple net effective pressure points are added; when the net effective pressure point remains unchanged, the displacement pressure difference is increased, and the core flow capacity is evaluated by liquid permeability measurement.

[0050] Step S3, such as Figure 7 , Figure 8 , Fig. 9 As shown, copper foil of the first thickness and copper foil of the second thickness are used to support the core fracture surface, so that the fracture has a corresponding opening, and the fracture support area reaches more than 80%, and its liquid permeability is calculated to evaluate the flow capacity of the core. The first thickness and the second thickness can be determined according to the actual situation in the laboratory.

[0051] Step S4, comprehensively evaluate the flow capacity of the core under stress conditions according to the corresponding fracture morphology, aperture, displacement pressure difference, net effective stress, etc. of the core, and calculate the liquid permeability of the core using Darcy's formula as follows:

[0052]

[0053] Where: K l —Rock liquid permeability, in units of 10 -3 μm 2 ;

[0054] μ—Viscosity of the fluid under test conditions, in millipascal seconds (mPa·s);

[0055] L—rock sample length, in centimeters (cm);

[0056] A—Cross-sectional area of ​​rock sample, in square centimeters (cm 2 );

[0057] p1—rock sample inlet pressure, in MPa;

[0058] p2—rock sample outlet pressure, in megapascals (MPa);

[0059] Q is the volume of fluid passing through the rock sample per unit time, in cubic centimeters per second (cm 3 / s).

[0060] like Fig.10 , Fig.11 , Fig.12 As shown in the figure, the flow capacity of the double-slit core under different fracture openings and effective stresses. The flow capacity of the core increases with the increase of the displacement pressure at the inlet, but the flow capacity curves of different fracture openings are inconsistent. According to the characteristics of the curves, they can be classified into two types: "convex" and "concave". Both types of curves reveal the characteristic that an increase in the inlet pressure will increase the flow at the outlet, but the increase will continue to decrease with the increase of the confining pressure.

[0061] Under the conditions of unsupported fracture aperture and second thickness supported fracture aperture, shale oil flow rate increases exponentially with the increase of inlet pressure, and the increasing equation can be written as:

[0062] y=ae bx (2)

[0063] In the formula, the coefficient a of the exponential increasing equation is related to the effective stress. The larger the effective stress, the smaller the value of a. The exponential coefficient b is determined by the shape of the curve as the inlet pressure increases, that is, it decreases first and then increases.

[0064] Under the condition of the first thickness supporting fracture opening, the shale oil flow rate increases logarithmically with the increase of inlet pressure, and the increasing equation can be written as:

[0065] y=c ln(x)-d (3)

[0066] In the formula, the fitting coefficient c of the logarithmic increasing equation is related to the effective stress. As the effective stress increases, the fitting coefficient c decreases linearly; d is the correction coefficient of the equation, which is determined by the curve shape reflected by different inlet pressures under the same effective stress conditions.

[0067] For cores with different fracture openings, the changing trend of shale oil flow capacity when the displacement pressure increases from 5 MPa to 16 MPa is summarized in Table 1.

[0068] Table 1 Variation characteristics of core flow rate with displacement pressure at different fracture openings

[0069]

[0070] Step S5, such as Fig.13 As shown in the figure, the reasonable flow pressure difference and effective stress are evaluated through the permeability relationship curve of the core under different fracture openings and flow pressure differences.

[0071] As can be seen from the figure, the permeability decreases with the increase of effective stress under all conditions. After the effective stress exceeds the threshold of the orange line of 6MPa, the downward trend of permeability becomes particularly obvious. This trend may be related to the closure of fractures inside the rock, resulting in a significant reduction in the flow capacity of the core. Especially in the effective stress range of 6MPa to 7MPa, it can be considered that the stress sensitivity of the rock has increased significantly, which is crucial for determining reasonable production operation parameters. Therefore, it is recommended to consider replenishing the formation as a reasonable pumping time within the effective stress range of 6MPa to 7MPa and the flow pressure difference range of 12MPa to 13MPa, which can maximize the use of formation pressure without causing excessive closure of rock fractures, and may help slow down the speed of fracture closure and maintain continuous oil and gas production. Such a strategy aims to use formation energy to replenish energy to ensure efficient production of fractured shale oil.

[0072] In the present application, a method for testing the fracture flow capacity of shale oil cores under stress conditions is provided, in which artificial fractures are created in the cores, so that the shale cores, which cannot be subjected to conventional displacement experiments, have a certain flow capacity; and different fracture morphologies can be simulated, making the experimental research more comprehensive, and providing a reference for the flow capacity of crude oil in fractured reservoirs in the current shale oil development.

[0073] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. A method for testing the fracture flow capacity of shale oil under core stress conditions, characterized in that: Includes steps: S1, core fracture; S2, vacuuming and high-pressure saturated oil treatment of the core after fracture creation; S3, according to the core fracture type, by changing the displacement pressure difference and confining pressure, multiple net effective stress points are added to obtain the flow data at the core outlet; S4, using copper foil to support the cracks, simulating different crack openings, adding multiple net effective stress points, obtaining flow data at the core outlet, and realizing the evaluation of shale core flow capacity under different crack opening conditions; S5, after selecting different flow pressure differences to achieve stable flow, obtain corresponding flow data, and calculate the liquid permeability of the fractured core according to Darcy's formula; S6, based on the result data, the core flow capacity is evaluated by integrating stress conditions and fracture morphology.

2. The method for testing the fracture flow capacity of shale oil under core stress conditions according to claim 1, characterized in that: Step S1 of core seam making includes using a seam splitting tool to obtain a core having a curved seam, a straight seam, or a double seam shape.

3. The method for testing the fracture flow capacity of shale oil under core stress conditions according to any one of claims 1 to 2, characterized in that: In step S2, a core with open bedding fractures is obtained by using an oil saturation process; and the dry core is subjected to vacuum evacuation and high-pressure oil saturation treatment.

4. The method for testing the fracture flow capacity of shale oil under core stress conditions according to any one of claims 1 to 2, characterized in that: Step S3 includes, under the same displacement pressure difference, adding multiple net effective pressure points; when the net effective pressure point remains unchanged, increasing the displacement pressure difference, and evaluating the core flow capacity by liquid permeability measurement.

5. The method for testing the fracture flow capacity of shale oil under core stress conditions according to any one of claims 1 to 2, characterized in that: Step S4 includes using copper foil to support the core fracture surface so that the fracture has a corresponding opening and the fracture support area reaches more than 80%, calculating its liquid permeability and evaluating the core flow capacity.

6. The method for testing the fracture flow capacity of shale oil under core stress conditions according to any one of claims 1 to 2, characterized in that: Step S5 includes: comprehensively evaluating the flow capacity of the core under stress conditions according to the corresponding fracture morphology, aperture, displacement pressure difference, net effective stress, etc. of the core, and calculating the liquid permeability of the core using Darcy's formula as follows: Where: K l — rock liquid permeability; μ—Fluid viscosity under test conditions; L—rock sample length; A—cross-sectional area of ​​rock sample; p1—rock sample inlet pressure; p2—rock sample outlet pressure; Q—The volume of fluid passing through the rock sample per unit time.

7. The method for testing the fracture flow capacity of shale oil under core stress conditions according to any one of claims 1 to 2, characterized in that: Step S5 also includes: the core flow capacity increases with the increase of the displacement pressure inlet end, and the flow capacity curves of different fracture openings have different shapes.

8. The method for testing the fracture flow capacity of shale oil under core stress conditions according to claim 7, characterized in that: Step S5 includes: under the conditions of unsupported fracture aperture and second thickness supported fracture aperture, the shale oil flow rate increases exponentially with the increase of inlet pressure, and the increasing equation is: y = ae bx In the formula, the coefficient a of the exponential increasing equation is related to the effective stress. The larger the effective stress, the smaller the value of a. The exponential coefficient b is determined by the shape of the curve as the inlet pressure increases, that is, it decreases first and then increases.

9. The method for testing the flow capacity of shale oil fractures under core stress conditions according to claim 7, characterized in that: Step S5 includes: under the condition of the first thickness supporting fracture opening, the shale oil flow rate increases logarithmically with the increase of the inlet pressure, and the increasing equation is: y=cln(x)-d, In the formula, the fitting coefficient c of the logarithmic increasing equation is related to the effective stress. As the effective stress increases, the fitting coefficient c decreases linearly; d is the correction coefficient of the equation, which is determined by the curve shape reflected by different inlet pressures under the same effective stress conditions.

10. The method for testing the fracture flow capacity of shale oil under core stress conditions according to any one of claims 1 to 2, characterized in that: Step S6 includes evaluating the reasonable flow pressure difference and effective stress through the permeability relationship curve of the core under different fracture apertures and flow pressure differences.

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