A method for characterizing the imbibition capacity in a water phase imbibition experiment of a shale gas reservoir core

Abstract

This invention discloses a method for characterizing the water-phase permeability of shale gas reservoir cores, relating to the field of unconventional shale oil and gas exploration and development technology. The invention includes a sample preparation step, where cores are prepared from lower columns or outcrops of the same stratigraphic position within a shale reservoir section; a sample processing step, where the cores are dried, and their cross-sectional area and weight are measured; the measured cores are then treated with epoxy resin to seal the non-permeable surface; a water-phase permeability test step, where the sealed cores undergo water-phase permeability testing to obtain experimental data; and the time data from the core test data is processed, and combined with the permeable end area and core mass, the permeability of the shale cores is characterized. This invention can accurately characterize the permeability of shale, accurately interpret the permeability of shale in a block, thus laying the foundation for quantitative analysis of production system optimization schemes for shale gas development and improving shale reservoir recovery rates.

Description

Technical Field

[0001] This invention relates to the field of unconventional shale oil and gas exploration and development technology, particularly to the field of shale oil and gas resource evaluation technology, and more specifically to a method for characterizing the permeability in the aqueous phase permeability test of shale gas reservoir cores. Background Technology

[0002] Shale is highly heterogeneous and significantly affected by hydration. During shale percolation experiments, the percolation process is influenced by various factors. Due to differences in sample size and structure, the percolation capacity of shale cannot be directly characterized by percolation rate versus time curves.

[0003] In addition, many factors influence shale permeability, including clay mineral content and type, porosity, and sample size. Analyzing the impact of these factors on shale permeability requires normalizing the influencing parameters. Shale has a complex pore structure and mineral composition, characterized by ultra-low porosity and permeability, while current characterization methods are mostly based on conventional rocks. For shale, a convenient and effective permeability characterization method has not yet been developed. Therefore, it is necessary to develop a method that utilizes spontaneous permeability experimental data to characterize shale's permeability capacity and absorption rate, and to analyze the permeability of shale samples.

[0004] Existing experimental characterization methods for measuring shale permeability are inaccurate and complex: the dimensionless time method requires precise measurement of rock sample physical parameters, otherwise the results will have large errors; the Olafuyi method is greatly affected by the porosity of the rock sample and cannot characterize the shale permeability rate; Makhanov's characterization method cannot characterize the maximum permeability of shale. Summary of the Invention

[0005] To overcome the defects and shortcomings of the existing technologies, this invention provides a method for characterizing the permeability of shale gas reservoir core aqueous phase permeability experiments. The purpose of this invention is to solve the problems of inaccuracy and complexity in the experimental characterization methods for measuring permeability in the existing technologies. This invention provides a quantitative analysis method that can normalize the shape and size of shale. This invention uses a normalization method based on the cross-sectional area per unit mass for comparative analysis and quantitative characterization. This invention can accurately characterize the permeability of shale and accurately interpret the permeability of shale in a block, thus laying the foundation for quantitative analysis of production system optimization schemes for shale gas development and improving the recovery rate of shale reservoirs.

[0006] To address the problems existing in the prior art, the present invention is achieved through the following technical solution:

[0007] A method for characterizing the permeability of shale gas reservoir core aqueous phase permeation experiments includes the following steps:

[0008] S1. Rock sample preparation steps: Select the corresponding rock sample and prepare the core according to the experimental conditions and purpose of the shale gas reservoir core water phase permeation test.

[0009] S2. Rock sample processing steps: Dry the rock core and measure its cross-sectional area and weight; treat the measured rock core with epoxy resin and seal the non-absorbent surface of the rock core.

[0010] S3. Water phase permeation test procedure: Conduct a water phase permeation test on the sealed core and obtain experimental data.

[0011] S4. The permeability evaluation step involves processing the time data in the core experimental data and characterizing the permeability of the shale core by combining the permeability end face and the core quality.

[0012] Furthermore, in step S2, the core cross-sectional area refers to the surface area of ​​the permeation section set in the experiment.

[0013] In step S2, the tested core is treated with epoxy resin. Specifically, epoxy resin is used to seal the non-absorbent surface of the core and then dried at 100°C for more than 24 hours until the core quality no longer changes.

[0014] The epoxy resin is a transparent flexible epoxy resin 6102, comprising adhesive A and adhesive B.

[0015] The experimental data refer to the infiltration time and core mass.

[0016] The non-permeable surface is determined based on the boundary conditions of the permeation experiment, including both ends of the core, a single end face, or the core column surface.

[0017] In step S3, the aqueous phase percolation experiment specifically involves:

[0018] S301. After being treated with epoxy resin, the core is fixed to the bottom of a suspended electronic balance with a non-absorbent nylon rope and placed in an empty beaker. The position of the core is adjusted so that it remains stable in the suspended state and does not contact the inner wall of the beaker.

[0019] S302. Add the percolating liquid to an empty beaker until it covers the percolating end face of the core, and record the weight on the electronic balance.

[0020] S303. Before obtaining the core weight data, remove the air bubbles generated on the core seepage end face during the seepage process; continuously record the core weight and seepage time during the seepage process until the core weight in the electronic balance tends to stabilize, and then stop the experiment.

[0021] In step S302, the percolating liquid is any one of distilled water, brine, or water-based fracturing fluid.

[0022] In step S4, the formula for characterizing the permeability of shale cores is:

[0023] In the formula, The volume of the core is the volume of the percolation, obtained by the ratio of the percolation mass to the density of the percolation fluid. Capillary pressure, unit: Pa; The core permeability is expressed in mD. Porosity, decimal; The value is the leading edge saturation, a decimal. The viscosity of the liquid is expressed in Pa·s. denoted as the surface area of ​​the core sample before the experiment, and M as the mass of the core sample before the experiment.

[0024] Furthermore, in step S4, the time data in the core experimental data is processed by raising it to the power of 0.5, and then multiplied by the ratio of the infiltration area to the rock sample mass as the abscissa. The experimental infiltration amount is divided by the rock sample mass as the ordinate; this is used to characterize the deviation curve of the relationship between infiltration amount and time.

[0025] Compared with the prior art, the beneficial technical effects of the present invention are as follows:

[0026] 1. Existing experimental evaluation methods for shale permeability are complex and inaccurate. This invention provides an evaluation and characterization method for shale gas reservoir core aqueous phase permeability experiments. This method is applicable to various shale permeability experimental conditions, including TEO (non-sealed at both ends) and AFO (fully permeable) conditions. The new analytical method introduces permeability and cross-sectional area per unit mass, normalizes core size, and eliminates the influence of core size and pore structure. Permeability time is processed using a power of 0.5, which can more intuitively represent the permeability rate. Combined with permeability experiments, the maximum permeability of the rock sample is determined by the permeability time expressed as the power of the permeability per unit mass and the permeability time. By analyzing shale permeability using the above method, the influence of rock sample size and pore structure on the analysis of experimental results is eliminated, and complex and time-consuming shale physical property tests are avoided. Compared with other permeability characterization methods, this method considers the maximum permeability of the rock sample. The experimental data processed using the new method can be directly compared with the permeation test results of samples from different blocks, thereby quickly and stably obtaining characteristic parameters such as the permeation rate of shale itself, providing support for theoretical research and field engineering analysis.

[0027] 2. The "elimination of the influence of porosity on the sample" in this application is reflected in: adding "unit mass parameter and permeation area" to the horizontal axis of the permeation curve. c / M; due to the strong heterogeneity of shale, the pore structures of formations at different well positions in the same block may be different. The previous characterization method of dialysis ability (imbibition area) can only outline the dialysis ability and cannot accurately characterize different core samples. A c The / M parameter can roughly reflect the differences in the internal structure of the samples (which can be similarly understood as density parameters), and practical applications have proved that this method has a good effect on improving accuracy. Brief Description of the Drawings

[0028] Figure 1 is the flowchart of the characterization method of the present invention;

[0029] Figure 2 is the characterization result of the imbibition ability of the core numbered "Wei 204H18-1-1" by using the characterization method of the present invention in an imbibition test;

[0030] Figure 3 is the characterization result of the imbibition ability of the core numbered "Wei 204-78" by using the characterization method of the present invention in an imbibition test;

[0031] Figure 4 is the curve graph of characterizing the imbibition ability of two tight sandstones by using the dimensionless time method;

[0032] Figure 5 is the curve graph of characterizing the imbibition ability of two tight sandstones by using the Olafuyi method;

[0033] Figure 6 is the curve graph of characterizing the imbibition ability of two tight sandstones by using the Markhanov method;

[0034] Figure 7 is the curve graph of characterizing the imbibition ability of two tight sandstones by using the method of the present invention;

[0035] Figure 8 is the test data processing graph after the aqueous phase imbibition of four different cores;

[0036] In the figure, Wei 204H18-1-1, Wei 204-78, S-1, S-2, CN1-1, CN2-1, YN-1 all represent rock numbers, where S-1 and S-2 are tight sandstones, and CN1-1, CN2-1 and YN-1 represent shales. Detailed Embodiments

[0037] The technical solutions of the present invention will be further elaborated in detail below in conjunction with the drawings of the specification. Obviously, the following embodiments only belong to a part of the embodiments of the technical solutions of the present invention, rather than all embodiments. Those embodiments obtained by those skilled in the art on the basis of the technical solutions of the present invention without creative labor belong to the protection scope of the present invention.

[0038] Example 1

[0039] As a preferred embodiment of the present invention, please refer to the appendix to the specification. Figure 1 This embodiment discloses:

[0040] A method for characterizing the permeability of shale gas reservoir core aqueous phase permeation experiments includes the following steps:

[0041] S1. Rock sample preparation steps: Select the corresponding rock sample and prepare the core according to the experimental conditions and purpose of the shale gas reservoir core water phase permeation test.

[0042] S2. Rock sample processing steps: Dry the rock core and measure its cross-sectional area and weight; treat the measured rock core with epoxy resin and seal the non-absorbent surface of the rock core.

[0043] S3. Water phase permeation test procedure: Conduct a water phase permeation test on the sealed core and obtain experimental data.

[0044] S4. The permeability evaluation step involves processing the time data in the core experimental data and characterizing the permeability of the shale core by combining the permeability end face and the core quality.

[0045] Example 2

[0046] As another preferred embodiment of the present invention, please refer to the appendix to the specification. Figure 1 , Figure 2 and Figure 3 As shown in this embodiment, a method for characterizing the permeability of shale gas reservoir core aqueous phase permeability experiments is disclosed, comprising the following steps:

[0047] S1. Rock sample preparation steps: Select the corresponding rock sample and prepare the core according to the experimental conditions and purpose of the shale gas reservoir core water phase permeation test.

[0048] In this embodiment, the characterization method does not have strict requirements on the source of the core sample; downhole cores, outcrop cores, or artificial cores can be flexibly selected according to experimental conditions and objectives. Figure 2 and Figure 3 As shown.

[0049] S2. Rock sample processing steps: Dry the two numbered core samples mentioned above, and measure the cross-sectional area and weight of the core samples. Treat the measured core samples with epoxy resin, sealing the non-absorbent surface of the core. The cross-sectional area of ​​the core refers to the surface area of ​​the designated absorbent section. Seal the non-absorbent surface of the core with epoxy resin and dry it at 100℃ for at least 24 hours until the core mass no longer changes. The epoxy resin is a transparent flexible epoxy resin 6102, including A-type and B-type components.

[0050] Steps of the aqueous imbibition experiment: Perform the aqueous imbibition experiment on the sealed core to obtain experimental data. Among them, perform the confining pressure, dynamic, and reverse spontaneous imbibition experiments on the core numbered "Wei 204H18-1-1"; perform the confining pressure, dynamic, and forward spontaneous imbibition experiments on the core numbered "Wei 204-78".

[0051] The experimental data refers to the imbibition time and the core mass. The set non-imbibition surface is determined according to the boundary conditions of the imbibition experiment, including the two end faces of the core, a single end face, or the core cylindrical surface.

[0052] The specific aqueous imbibition experiment is as follows:

[0053] S301. The core after being treated with epoxy resin is fixed to the bottom of a hanging electronic balance through a non-water-absorbent nylon rope and placed in an empty beaker. Adjust the position of the core so that the core remains stable in the hanging state and does not contact the inner wall of the beaker.

[0054] S302. Add the imbibition liquid into the empty beaker to submerge the imbibition end face of the core, and record the weight of the electronic balance.

[0055] S303. Before obtaining the core weight data, remove the bubbles generated by the imbibition liquid on the imbibition end face of the core during the imbibition process; continuously record the weight of the core and the imbibition time during the imbibition process until the weight of the core in the electronic balance tends to be stable, and then stop the experiment. In the S302 step, the imbibition liquid is any one of distilled water, brine, or water-based fracturing fluid.

[0056] S4. Steps for evaluating the imbibition ability: Process the time data in the core experimental data, and combine the imbibition end face of the core and the core mass to characterize the imbibition ability of the shale core. The results are as Figure 2 and Figure 3 shown. In the S4 step, the formula for characterizing the imbibition ability of the shale core is:

[0057] , where, is the imbibition volume of the core, obtained by the ratio of the imbibition mass to the density of the imbibition liquid; is the capillary pressure, with the unit of Pa; is the core permeability, in mD; is the porosity, in decimal; is the front saturation, in decimal; is the liquid viscosity, in Pa·s; denoted as , where is the surface area of ​​the infiltration area before the experiment, and M is the mass of the core sample before the experiment. In step S4, the time data in the core experiment data is processed by raising it to the power of 0.5, multiplied by the ratio of the infiltration area to the mass of the rock sample as the abscissa, and the experimental infiltration amount is divided by the mass of the rock sample as the ordinate; this is used to characterize the deviation of the infiltration amount from the time relationship curve.

[0058] Example 3

[0059] As another preferred embodiment of the present invention, please refer to the appendix to the specification. Figure 4 , Figure 5 , Figure 6 and Figure 7 This embodiment discloses:

[0060] Two types of tight sandstone were selected, and the specific parameters of the core samples are shown below:

[0061]

[0062] To visually compare the characteristics of each characterization method, this embodiment uses a tight sandstone sample for a permeation experiment (tight sandstone exhibits less water-rock reaction compared to shale and can be reused. In the petroleum industry, methods for characterizing the permeation capacity of shale are all verified using the permeation of tight sandstone).

[0063] The characterization methods are shown in the table below:

[0064]

[0065] The horizontal and vertical axes of the curves for the four characterization methods are shown in the table below:

[0066]

[0067] The characterization curve of the dimensionless time method is as follows: Figure 4 As shown, the characterization results curve of the Olafui method are as follows: Figure 5 As shown, the characterization results curve of the Makhanov method are as follows: Figure 6 As shown, the characterization result curves of the characterization method in this application are as follows: Figure 7 As shown, the new characterization method produces similar core curves for tight sandstone of different lengths within the same stratum, indicating that it provides higher accuracy in characterizing permeability and is less affected by sample size.

[0068] Example 4

[0069] As another embodiment of the present invention, please refer to the appendix to the specification. Figure 8This embodiment discloses a method for characterizing the permeability of shale gas reservoir cores in a water phase permeation test. In this embodiment, one tight sandstone core, designated S-1, and three shale cores, designated YN-1, CN1-1, CN2-1, and YN-1, were selected. Water phase permeation tests were conducted on the four different cores.

[0070] Four core samples were dried, and their cross-sectional area and weight were measured. The measured core samples were then treated with epoxy resin to seal the non-absorbent surface. The cross-sectional area of ​​the core refers to the area of ​​the designated absorbent surface. Specifically, the epoxy resin treatment involved sealing the non-absorbent surface of the core with epoxy resin and drying it at 100°C for at least 24 hours until the core mass no longer changed. The epoxy resin used was a transparent, flexible epoxy resin 6102, comprising adhesive A and adhesive B. The non-absorbent surface was determined based on the boundary conditions of the absorbency experiment and could include both ends of the core, a single end, or the core column surface.

[0071] The aqueous phase percolation experiment is as follows: After epoxy resin treatment, the core is fixed to the bottom of a suspended electronic balance with a non-absorbent nylon rope and placed in an empty beaker. The position of the core is adjusted to ensure that it remains stable in the suspended state and does not touch the inner wall of the beaker. Percolation liquid is added to the empty beaker, covering the percolation end face of the core, and the weight of the electronic balance is recorded. Before obtaining the core weight data, air bubbles generated on the percolation end face of the core during the percolation process are removed. The weight of the core and the percolation time are continuously recorded during the percolation process until the weight of the core in the electronic balance tends to stabilize, at which point the experiment is stopped.

[0072] The steps for evaluating the permeability of shale cores involve processing the time data from the core experiments and combining this data with the permeability profile and core mass to characterize the permeability of the shale cores. The formula for characterizing the permeability of shale cores is as follows:

[0073] In the formula, The volume of the core is the volume of the percolation, obtained by the ratio of the percolation mass to the density of the percolation fluid. Capillary pressure, unit: Pa; The core permeability is expressed in mD. Porosity, decimal; The value is the leading edge saturation, a decimal. The viscosity of the liquid is expressed in Pa·s. denoted as the surface area of ​​the core sample before the experiment, and M as the mass of the core sample before the experiment.

[0074] The time data in the core experiment were processed by raising it to the power of 0.5, and then multiplied by the ratio of the infiltration area to the rock sample mass as the x-axis. The experimental infiltration amount was divided by the rock sample mass as the y-axis; this was used to characterize the deviation of the infiltration amount from the time-time curve. The results are as follows: Figure 8 As shown.

[0075] The following table shows some experimental data after water phase infiltration and absorption from four different core samples during the above experiment:

[0076]

[0077] The above experimental results and data show that this invention is applicable to various shale permeability test conditions, including TEO (non-sealed at both ends) and AFO (fully permeable) shale. The new analytical method introduces the permeability and cross-sectional area per unit mass, normalizes the core size, and eliminates the influence of core size and pore structure. The permeation time is processed using a power of 0.5, which provides a more intuitive characterization of the permeation rate. Combined with permeation experiments, the maximum permeability of the rock sample is determined by the permeation time expressed as the power of the permeability per unit mass and the permeation time. Analyzing shale permeability using this method eliminates the influence of rock sample size and pore structure on the experimental results, avoids complex and time-consuming shale physical property tests, and considers the maximum permeability of the rock sample compared to other permeability characterization methods. Experimental data processed using the new method can be directly compared with permeation test results from samples in different blocks, thereby quickly and stably obtaining characteristic parameters such as the permeation rate of shale itself, providing support for theoretical research and field engineering analysis.

Claims

1. A method for characterizing the permeability of shale gas reservoir core water phase in an experiment, characterized in that: Includes the following steps: S1. Rock sample preparation steps: Select the corresponding rock sample and prepare the core according to the experimental conditions and purpose of the shale gas reservoir core water phase permeation test. S2. Rock sample processing steps: Dry the rock core, measure the cross-sectional area and weight of the rock core, where the cross-sectional area of ​​the rock core refers to the surface area of ​​the set permeable section; treat the measured rock core with epoxy resin, fix the rock core to the non-permeable section, use epoxy resin to fix the non-permeable surface of the rock core, and dry it at 100°C for more than 24 hours until the rock core quality no longer changes. S3. Water phase infiltration test procedure: The sealed core is subjected to a water phase infiltration test to obtain experimental data, which refers to the infiltration time and core mass. The water phase infiltration test is specifically as follows: S301. After being treated with epoxy resin, the core is fixed to the bottom of a suspended electronic balance with a non-absorbent nylon rope and placed in an empty beaker. The position of the core is adjusted so that it remains stable in the suspended state and does not contact the inner wall of the beaker. S302. Add the percolating liquid to an empty beaker until it covers the percolating end face of the core, and record the weight on the electronic balance. S303. Before obtaining the core weight data, remove the air bubbles generated on the core seepage end face during the seepage process; continuously record the core weight and seepage time during the seepage process until the core weight in the electronic balance tends to stabilize, and stop the experiment. S4. The permeability evaluation step involves processing the time data from the core test data and, in conjunction with the permeability end face and core quality, characterizing the permeability of the shale core. The formula for characterizing the permeability of the shale core is: In the formula, The volume of the core is the volume of the percolation, obtained by the ratio of the percolation mass to the density of the percolation fluid. Capillary pressure, unit: Pa; K The core permeability is expressed in mD. Porosity, decimal; The value is the leading edge saturation, a decimal. The viscosity of the liquid is expressed in Pa·s. denoted as , where is the area of ​​the infiltration surface before the experiment, and M is the mass of the core sample before the experiment. The time data in the core experiment is processed by raising it to the power of 0.5, and then multiplied by the ratio of the infiltration area to the mass of the rock sample as the abscissa. The experimental infiltration amount is divided by the mass of the rock sample as the ordinate. This is used to characterize the deviation of the infiltration amount from the time relationship curve.

2. The method for characterizing the permeability in the aqueous phase permeation experiment of a shale gas reservoir core as described in claim 1, characterized in that: The epoxy resin is a transparent flexible epoxy resin 6102, comprising adhesive A and adhesive B.

3. The method for characterizing the permeability in the aqueous phase permeation experiment of a shale gas reservoir core as described in claim 1, characterized in that: The non-permeable surface is determined based on the boundary conditions of the permeation experiment, including both ends of the core, a single end face, or the core column surface.

4. The method for characterizing the permeability in the aqueous phase permeation experiment of a shale gas reservoir core as described in claim 1, characterized in that: In step S302, the percolating liquid is any one of distilled water, brine, or water-based fracturing fluid.

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