Method and device for determining sandstone drainage pressure differential range

Abstract

The application discloses a method and device for determining a sandstone drainage pressure differential range, wherein the method comprises the following steps: cutting a dense sandstone sample into a first sample and a second sample; performing T2 mapping test on the first sample, obtaining a T2 mapping test result and performing inversion to determine a pore size distribution curve of the T2 mapping; performing mercury injection test on the second sample, obtaining a mercury injection test result and performing inversion to determine a pore size distribution graph of the mercury injection; establishing a conversion relationship between the T2 mapping and the pore size distribution of the T2 mapping according to the corresponding relationship between the pore size distribution curve of the T2 mapping and the pore size distribution graph of the mercury injection; and converting the T2 mapping into fracturing fluid and imbibition and / or flowback distribution results in different pore sizes according to the established conversion relationship, so as to accurately determine the sandstone drainage pressure differential range, and reduce the damage of the dense sandstone gas reservoir fracturing fluid according to the microcosmic dynamic distribution of the sandstone gas reservoir fracturing fluid.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field development, and in particular to a method and device for determining a sandstone drainage pressure difference range. Background Art

[0002] This section is intended to provide a background or context to the embodiments of the invention that are recited in the claims. No statement herein is admitted to be prior art by virtue of its inclusion in this section.

[0003] Tight sandstone gas, a typical unconventional natural gas resource, holds great development potential. Tight sandstone gas reservoirs lack natural productivity, making large-scale hydraulic fracturing the key to developing these reservoirs. Visualizing the microscopic distribution of gas and water within reservoir pores during fracturing fluid imbibition along fractures and flowback is crucial for optimizing fracturing techniques and post-fracturing flowback systems.

[0004] Currently, core-scale physical simulation experiments are often used to study the dynamic distribution of fracturing fluid in reservoirs during imbibition and flowback. Based on geological understanding and simulating reservoir conditions, plunger or full-diameter core physical simulations are widely used to study gas-water flow in conventional reservoirs. However, in dense rock, seepage is primarily micro- and nano-scale, with more complex interfacial effects and flow mechanisms. Conventional experimental methods and approaches are no longer sufficient to study the microscopic distribution of dense rock. Summary of the Invention

[0005] An embodiment of the present invention provides a method for determining a sandstone drainage pressure differential range, for accurately determining the sandstone drainage pressure differential range. The method includes:

[0006] The dense sandstone sample is cut into the first section sample and the second section sample;

[0007] Performing a T2 spectrum test on the first section of the sample, obtaining the T2 spectrum test results and performing inversion to determine the pore size distribution curve of the T2 spectrum;

[0008] Perform mercury intrusion testing on the second section of sample, obtain the mercury intrusion test results and perform inversion to determine the mercury intrusion pore size distribution map;

[0009] According to the corresponding relationship between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of mercury intrusion, a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is established;

[0010] According to the established conversion relationship, the T2 map is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes. Based on the distribution results, the pore production efficiency is calculated and the drainage pressure difference range of tight sandstone samples is determined.

[0011] An embodiment of the present invention further provides a device for determining a sandstone drainage pressure differential range, adapted to the specific conditions of tight sandstone gas reservoirs and reducing damage to fracturing fluid in tight sandstone gas reservoirs. The device comprises:

[0012] A sample cutting module, used for cutting a dense sandstone sample into a first section sample and a second section sample;

[0013] A pore size distribution curve determination module is used to perform a T2 spectrum test on the first section of samples, obtain the T2 spectrum test results and perform inversion to determine the pore size distribution curve of the T2 spectrum;

[0014] A pore size distribution map determination module is used to perform a mercury injection test on the second section sample, obtain the mercury injection test results and perform inversion to determine the mercury injection pore size distribution map;

[0015] A conversion relationship establishment module is used to establish a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum according to the corresponding relationship between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of mercury intrusion;

[0016] The distribution result acquisition module is used to convert the T2 map into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes based on the established conversion relationship. Based on the distribution results, the pore utilization efficiency is calculated and the drainage pressure difference range of the tight sandstone sample is determined.

[0017] An embodiment of the present invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, the above-mentioned method for determining the sandstone drainage pressure difference range is implemented.

[0018] An embodiment of the present invention further provides a computer-readable storage medium storing a computer program. When the computer program is executed by a processor, the method for determining the sandstone drainage pressure difference range is implemented.

[0019] An embodiment of the present invention further provides a computer program product, which includes a computer program. When the computer program is executed by a processor, it implements the above-mentioned method for determining the sandstone drainage pressure difference range.

[0020] In an embodiment of the present invention, a tight sandstone sample is cut into a first sample section and a second sample section; a T2 map test is performed on the first sample section, the T2 map test result is obtained and inversion is performed to determine the pore size distribution curve of the T2 map; a mercury injection test is performed on the second sample section, the mercury injection test result is obtained and inversion is performed to determine the pore size distribution diagram of the mercury injection; based on the correspondence between the pore size distribution curve of the T2 map and the pore size distribution diagram of the mercury injection, a conversion relationship between the T2 map and the pore size distribution of the T2 map is established; based on the established conversion relationship, the T2 map is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes, and based on the distribution results, the utilization efficiency of the pores is calculated to determine the drainage pressure difference range of the tight sandstone sample, thereby accurately determining the sandstone drainage pressure difference range, so as to reduce the damage of the fracturing fluid in the tight sandstone gas reservoir according to the microscopic dynamic distribution of the fracturing fluid in the sandstone gas reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for the embodiments or the description of the prior art. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative work. In the drawings:

[0022] Figure 1 This is a flow chart of a method for determining a sandstone drainage pressure differential range in an embodiment of the present invention;

[0023] Figure 2 This is a diagram showing the experimental sample design results in an embodiment of the present invention;

[0024] Figure 3 The saturated water T2 spectrum result diagram and permeability contribution conversion curve in the embodiment of the present invention;

[0025] Figure 4 The NMR images and cumulative permeability contribution results after gas flooding at different displacement pressure differences in the embodiment of the present invention are shown;

[0026] Figure 5 This is the optimal result of the drainage pressure difference considering the pore production efficiency of the matrix in the embodiment of the present invention;

[0027] Figure 6 This is a diagram of the T2 spectrum results in an embodiment of the present invention;

[0028] Figure 7 This is a diagram showing the fitting results of the core pore throat radius and relaxation time in an embodiment of the present invention;

[0029] Figure 8 This is a T2 spectrum result diagram of the fracturing fluid imbibition and invasion process in an embodiment of the present invention;

[0030] Figure 9 This is a diagram showing the microscopic distribution of gas and water during the imbibition and invasion process of the fracturing fluid in an embodiment of the present invention;

[0031] Figure 10 This is a T2 spectrum result diagram of the gas drive fracturing fluid flowback process in an embodiment of the present invention;

[0032] Figure 11 This is a diagram showing the gas-water microscopic distribution results during the flowback process of the gas-driven fracturing fluid in an embodiment of the present invention;

[0033] Figure 12 Schematic diagram of a device for determining the pressure difference range of sandstone drainage in an embodiment of the present invention. DETAILED DESCRIPTION

[0034] To make the purpose, technical solutions and advantages of the embodiments of the present invention more clear, the embodiments of the present invention are further described in detail below with reference to the accompanying drawings. Here, the exemplary embodiments of the present invention and their descriptions are used to explain the present invention, but are not intended to limit the present invention.

[0035] Figure 1 This is a flow chart of a method for determining a sandstone drainage pressure differential range in an embodiment of the present invention. The method includes:

[0036] Step 101, cutting a dense sandstone sample into a first section sample and a second section sample;

[0037] Step 102: Perform a T2 spectrum test on the first sample, obtain the T2 spectrum test results, perform inversion, and determine the pore size distribution curve of the T2 spectrum;

[0038] Step 103: perform a mercury injection test on the second section of the sample, obtain the mercury injection test results, perform inversion, and determine the mercury injection pore size distribution map;

[0039] Step 104, establishing a conversion relationship between the T2 map and the pore size distribution of the T2 map based on the corresponding relationship between the pore size distribution curve of the T2 map and the pore size distribution map of mercury intrusion;

[0040] Step 105: Based on the established conversion relationship, the T2 map is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes. Based on the distribution results, the pore production efficiency is calculated to determine the drainage pressure difference range of the tight sandstone sample.

[0041] Each step is described in detail below.

[0042] In step 101 , a dense sandstone sample is cut into a first section sample and a second section sample.

[0043] In one embodiment, before dividing the tight sandstone sample into a first section sample and a second section sample, the method includes:

[0044] The tight sandstone samples were subjected to salt and oil washing pretreatment and aging pretreatment.

[0045] In a specific embodiment, a typical dense sandstone sample was selected. Considering the salt accumulation problem caused by the rapid temperature and pressure changes during the coring process, the experimental sample was pretreated by washing the salt and oil. After pretreatment, the porosity and permeability were tested and then vacuum dried for 24 hours. The pretreated rock sample was then cut into two sections, A and B. Section A was intended for 100% saturated formation water nuclear magnetic resonance experiments, and section B was intended for high-pressure mercury injection experiments. The specific experimental sample design results are shown in the attached figure. Figure 2 Among them, the tight sandstone samples were selected for oil and salt washing pretreatment to prevent the temperature and pressure changes during the downhole coring process from inducing salt formation and causing changes in pore structure; the tight sandstone samples were subjected to aging pretreatment to prevent the stress changes during the experiment from affecting the changes in the core pore structure, as shown in the figure. Figure 2 The data results are shown in Table 1. The core was cut into two sections, section A was used for 100% saturated simulated formation water NMR experiments, and section B was used for high-pressure mercury injection experiments.

[0046] Table 1 Saturated water NMR test results

[0047]

[0048]

[0049] In step 102, a T2 spectrum test is performed on the first section of the sample, and the T2 spectrum test results are obtained and inverted to determine the pore size distribution curve of the T2 spectrum.

[0050] In a specific embodiment, simulated formation water was prepared. Based on the dense sandstone sample prepared in step 1, the simulated formation water was saturated in section A using a high-pressure saturation device for 72 hours, and the core quality before and after saturation was recorded. Subsequently, the dense sandstone sample in section A was placed in a low-field nuclear magnetic resonance test device for saturated T2 spectrum testing. The measured T2 spectrum results are as follows: Figure 6 As shown in the figure, mercury injection experiments were conducted on samples from Section B using a high-pressure mercury injection tester to obtain mercury intrusion and decompression curves, and the mercury injection pore size distribution map was obtained by inversion. The core was evacuated for 48 hours and saturated with formation water under in situ effective stress for 72 hours. Standard samples were placed in a nuclear magnetic resonance instrument for calibration. The water-saturated T2 spectrum and cumulative distribution frequency diagram of the tight sandstone samples from Section A were measured using a low-field nuclear magnetic resonance instrument. The mercury injection pore size distribution map of the tight sandstone samples from Section B was determined using the high-pressure mercury injection tester.

[0051] In step 103, a mercury injection test is performed on the second section of the sample, and the mercury injection test results are obtained and inverted to determine the mercury injection pore size distribution map.

[0052] In one embodiment, obtaining mercury injection test results and performing inversion includes:

[0053] According to the mercury injection test results, the mercury inlet and outlet curves are obtained;

[0054] The mercury injection and withdrawal curves are inverted to obtain the pore size distribution diagram of mercury injection.

[0055] In this specific embodiment, a water-saturated NMR T2 distribution spectrum and cumulative frequency distribution spectrum were obtained for the sample in Section A, as well as a mercury injection pore size distribution spectrum for Section B. Because the pore throat structures of core samples at the same depth and location are not significantly different, the pore size distribution curve obtained from the NMR T2 spectrum in Section A and the pore size distribution curve obtained by mercury injection in Section B have a strong correspondence. By fitting the relaxation time and pore throat radius corresponding to the same cumulative distribution frequency, a conversion relationship between the NMR T2 spectrum and the pore size distribution can be obtained. After obtaining the conversion coefficient, the microscopic distribution characteristics of the fracturing fluid in the reservoir under different processes and at different times can be quantitatively evaluated.

[0056] The transverse relaxation time T2 of porous media depends on the pore throat structure of the porous media, and the surface relaxation rate has a significant impact on it. The specific surface area of ​​a single pore is the ratio of the pore shape factor to the pore radius. For the same core, the surface relaxation rate ρ and the pore shape factor FS can be approximately constant, so C can also be regarded as a constant. Plot the fitting spectrum of relaxation time and pore throat radius corresponding to the same cumulative distribution frequency. The slope of the two is the corresponding conversion coefficient C, as shown in Figure 7 shown.

[0057] In step 104, a conversion relationship between the T2 map and the pore size distribution of the T2 map is established based on the corresponding relationship between the pore size distribution curve of the T2 map and the pore size distribution map of mercury intrusion.

[0058] In one embodiment, based on the correspondence between the pore size distribution curve of the T2 map and the pore size distribution map of mercury intrusion, a conversion relationship between the T2 map and the pore size distribution of the T2 map is established, including:

[0059] The relaxation time and pore throat radius corresponding to the distribution frequency in the mercury injection test results are fitted, and the conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is obtained based on the fitting results.

[0060] In one embodiment, obtaining a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum according to the fitting result includes:

[0061] Calculate the conversion factor using the following formula:

[0062]

[0063] Where T2 is the relaxation time, ρ is the relaxation rate, and F s is a constant, r is the pore radius of tight sandstone, and C is the conversion coefficient.

[0064] In step 105, the T2 map is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes according to the established conversion relationship. Based on the distribution results, the pore production efficiency is calculated to determine the drainage pressure difference range of the tight sandstone sample.

[0065] According to Poiseuille theory, rock can be equivalent to capillaries of unequal diameters, and the flow rate formula of a single capillary can be calculated as:

[0066]

[0067] Q is the flow rate, m 3 / s; R is the capillary radius, μm; P is the pressure difference, MPa; η is the fluid viscosity coefficient; L is the length, m.

[0068] Combined with Darcy's formula, the calculation formula for the permeability of a single capillary tube can be obtained:

[0069]

[0070] K is permeability, mD; φ is porosity, %; r i is the pore throat radius, μm; n is the equivalent pore throat number;

[0071] After calculating the interval permeability, the permeability contribution curve can be calculated based on the NMR signal increment, and then the pore utilization efficiency chart of different blocks can be obtained:

[0072]

[0073] i is the number of the i-th observation point in the segmented sampling, φ is the porosity, %; T2 is the nuclear magnetic signal value;

[0074] The cumulative penetration contribution rate can be obtained according to the following formula:

[0075]

[0076] C i is the cumulative contribution value; φ is the porosity, %; T2 is the nuclear magnetic signal value; i is the observation point number.

[0077] The cumulative distribution curve of permeability contribution is obtained based on the saturated water nuclear magnetic spectrum. The data table is shown in Table 2, and the drawing results are shown in Figure 3 In this embodiment, based on Table 2, the cumulative values ​​of permeability contribution are 90.0%, 95.0%, 99.0%, and 99.99%, and the corresponding relaxation times are 99.54ms, 75.62ms, 41.75ms, and 3.65ms, respectively. Figure 3The contribution of each pore throat interval to the permeability can be determined. In this embodiment, the main contribution to the permeability is made by pores larger than 99.54ms. The micron-scale pores corresponding to 41.75ms to 99.54ms contribute about 10% to the permeability, and the nano-scale pores smaller than 2.65ms basically do not contribute to the permeability. It can be seen from this that the lower limit of the drainage pressure difference must at least be able to mobilize fluids in pores larger than 99.54ms, while the upper limit of the drainage pressure difference only needs to be able to mobilize fluids in pores larger than 75.62ms. Without considering the damage to particle migration or other problems induced by large pressure differences, if the recovery rate needs to be further improved, the pressure difference can be adjusted to the drainage pressure difference corresponding to the fluid in pores larger than 41.75ms. Furthermore, excessive pressure differentials should not be pursued blindly. The research results of this patent show that even if the pressure differential is adjusted to a very large value, allowing fluid in pores below 41.75ms to be mobilized, this contribution to permeability and productivity is relatively low. On the contrary, excessive pressure differentials can induce damage to particle migration and potentially induce the conversion of a large amount of secondary movable water into movable water, leading to problems such as premature water breakthrough in gas wells. Therefore, obtaining these data can provide a basis for subsequent steps in determining the efficiency of matrix pore throat utilization and the range of drainage pressure differentials.

[0078] Table 2 Cumulative results of permeability contribution based on NMR increment changes

[0079]

[0080]

[0081] Based on the porosity, permeability, length and diameter of the selected typical experimental cores, combined with the specific effective stress and drainage pressure gradient of the block reservoir, the corresponding experimental confining pressure and a set of displacement pressures and displacement times are determined.

[0082] In a specific embodiment, reverse gas displacement is performed on a core that has completed a fracturing fluid imbibition and intrusion experiment along a hydraulic fracture. The gas-driven fracturing fluid is flowed back based on a set displacement pressure differential and displacement time. A T2 map is obtained after the displacement is completed, and the gas-fracturing fluid distribution is inverted. Specifically, the displacement pressure is 0.1 to 10 MPa, gradually increasing throughout the experiment. Preferably, the displacement pressure can be adjusted based on the specific physical properties of the reservoir. The displacement time is 30 minutes, and the confining pressure should always be at least 3 MPa greater than the displacement flow pressure differential to ensure seepage stability.

[0083] The gradient range of displacement pressure difference is 0.5~8MPa, the displacement time is 30min, and the confining pressure is 3.5~11MPa to ensure the effective stress remains unchanged and the flow is stable.

[0084] The block pore utilization efficiency chart is obtained based on the change in the nuclear magnetic signal. The cumulative permeability contribution values ​​obtained are 90.0%, 95.0%, and 99.99%, respectively. The corresponding relaxation times are Figure 4 Mark in.

[0085] In a specific embodiment, the NMR images after gas flooding with different pressure differences are as follows: Figure 4 As shown in the figure, after displacement at a 0.5 MPa differential pressure, a significant amount of fluid remains unused in pores longer than 99.54 ms. As the differential pressure increases to 2 MPa, fluid in pores longer than 99.54 ms is effectively mobilized, but some fluid remains unmobilized in the pores between 75.62 ms and 99.54 ms. At this point, the fluid utilization efficiency in these pore throats is 64.34%. Further increasing the differential pressure to 3 MPa, the fluid utilization efficiency in the pores between 75.62 ms and 99.54 ms reaches approximately 90%. Continuing to increase the differential pressure until the differential pressure reaches 8 MPa, it is observed that at 8 MPa, the fluid utilization efficiency in the pores between 75.62 ms and 99.54 ms increases to approximately 93%, and the fluid utilization efficiency in the pores between 3.65 ms and 75.62 ms increases by 20.54%. A pressure difference of 3 MPa has basically met the requirements of being able to mobilize the fluid in the pores without inducing additional particle migration damage and large amounts of water production. If the pressure difference is greater than 3 MPa, the fluid utilization efficiency will be improved to a certain extent, but the improvement is not significant, and it will cause the energy consumption of the gas reservoir to be faster, and water will appear too early in the later stage, resulting in a decrease in production. Figure 5 As mentioned above, the pressure difference of 3 MPa is the final optimized pressure difference, and it is also the drainage pressure difference value optimized considering the fluid utilization efficiency. Drainage or production based on this pressure difference can ensure that the fluid in the pores can be fully utilized without causing additional particle migration damage and large-scale formation water production.

[0086] In a specific embodiment, the fracturing fluid formula for the mine is configured with reference to the industry standard SY / T51072016 "Method for evaluating the performance of water-based fracturing fluid", and the properties of the fracturing fluid are tested to ensure consistency with the mine performance. The imbibition and invasion process of the fracturing fluid after fracturing is simulated, and the forced imbibition and invasion of the fracturing fluid is simulated under a pressure difference of 3.5 MPa. The nuclear magnetic T2 spectrum test is carried out at 30 minutes, 60 minutes, 90 minutes, 150 minutes, 210 minutes, and 300 minutes of imbibition and invasion, and the T2 spectrum is converted into the microscopic distribution results of the fracturing fluid and gas phase in pores of different sizes according to the conversion formula, and the gas-water distribution plate after the fracturing fluid invasion at different time and space stages is obtained, such as Figure 8 Shown and Figure 9As shown in the figure, this provides a certain reference for the optimization of fracturing construction measures; among them, fracturing fluid imbibition and invasion experiments are carried out under reservoir temperature and effective stress, and nuclear magnetic T2 spectrum tests are obtained at different times. The conversion relationship between nuclear magnetic T2 spectrum and pore size distribution is fitted and established, and the T2 spectrum is converted into the micro-distribution results of fracturing fluid and gas phase in different pore sizes; fracturing fluid invasion plates at different time and space stages are obtained.

[0087] In a specific embodiment, the flowback process of gas-driven fracturing fluid after fracturing is simulated, the displacement direction is reversed, and high-purity nitrogen is used to reversely displace the core after the fracturing fluid invades. Nuclear magnetic resonance T2 spectrum tests are performed at 20 minutes, 60 minutes, 120 minutes, 180 minutes, 240 minutes, and 300 minutes of displacement invasion, and then the T2 spectrum is converted into the microscopic distribution results of fracturing fluid and gas phase in pores of different sizes according to the conversion formula to obtain the gas-water distribution plate after the flowback of gas-driven fracturing fluid at different time and space stages, as shown in FIG. Figure 10 and Figure 11 As shown, the microscopic distribution characteristics of the fracturing fluid in the reservoir under different processes and at different times can be quickly evaluated, so that corresponding fracturing construction measures and post-fracturing flowback systems can be formulated to achieve efficient drainage and gas recovery in tight gas reservoirs, and ultimately improve the EUR of the gas reservoir. Gas drive fracturing fluid flowback experiments are carried out under reservoir temperature and effective stress; nuclear magnetic T2 spectrum tests are obtained at different times; T2 spectra are converted into microscopic distribution results of fracturing fluid and gas phase in different pore sizes; and gas-water distribution maps after gas drive fracturing fluid flowback at different time and space stages are obtained.

[0088] The present invention also provides a device for determining the pressure difference range of sandstone drainage, as described in the following embodiments. Since the principle of the device to solve the problem is similar to the method for determining the pressure difference range of sandstone drainage, the implementation of the device can refer to the implementation of the method for determining the pressure difference range of sandstone drainage, and the repeated parts will not be repeated. Figure 12 The device shown comprises:

[0089] A sample cutting module 121 is used to cut the dense sandstone sample into a first sample segment and a second sample segment;

[0090] A pore size distribution curve determination module 122 is used to perform a T2 spectrum test on the first section of samples, obtain the T2 spectrum test results and perform inversion to determine the pore size distribution curve of the T2 spectrum;

[0091] A pore size distribution map determining module 123 is configured to perform a mercury intrusion test on the second section of the sample, obtain the mercury intrusion test results, perform inversion, and determine a mercury intrusion pore size distribution map;

[0092] A conversion relationship establishing module 124 is used to establish a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum based on the corresponding relationship between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of mercury intrusion;

[0093] The distribution result acquisition module 125 is used to convert the T2 map into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes based on the established conversion relationship, calculate the pore utilization efficiency based on the distribution results, and determine the drainage pressure difference range of the tight sandstone sample.

[0094] In one embodiment, a sample pre-processing module is further included, for:

[0095] Before the sample cutting module divides the dense sandstone sample into the first section sample and the second section sample, the dense sandstone sample is subjected to salt and oil washing pretreatment and aging pretreatment.

[0096] In one embodiment, the pore size distribution map determining module 122 is specifically configured to:

[0097] According to the mercury injection test results, the mercury inlet and outlet curves are obtained;

[0098] The mercury injection and withdrawal curves are inverted to obtain the pore size distribution diagram of mercury injection.

[0099] In one embodiment, the conversion relationship establishing module 124 is specifically configured to:

[0100] The relaxation time and pore throat radius corresponding to the distribution frequency in the mercury injection test results are fitted, and the conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is obtained based on the fitting results.

[0101] In one embodiment, the conversion relationship establishing module 124 is specifically configured to:

[0102] Calculate the conversion factor using the following formula:

[0103]

[0104] Where T2 is the relaxation time, ρ is the relaxation rate, and F s is a constant, r is the pore radius of tight sandstone, and C is the conversion coefficient.

[0105] An embodiment of the present invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, the above-mentioned method for determining the sandstone drainage pressure difference range is implemented.

[0106] An embodiment of the present invention further provides a computer-readable storage medium storing a computer program. When the computer program is executed by a processor, the method for determining the sandstone drainage pressure difference range is implemented.

[0107] An embodiment of the present invention further provides a computer program product, which includes a computer program. When the computer program is executed by a processor, it implements the above-mentioned method for determining the sandstone drainage pressure difference range.

[0108] In an embodiment of the present invention, a tight sandstone sample is cut into a first sample and a second sample; a T2 map test is performed on the first sample, the T2 map test results are obtained and inverted, and the pore size distribution curve of the T2 map is determined; a mercury injection test is performed on the second sample, the mercury injection test results are obtained and inverted, and the pore size distribution diagram of the mercury injection is determined; based on the correspondence between the pore size distribution curve of the T2 map and the pore size distribution diagram of the mercury injection, a conversion relationship between the T2 map and the pore size distribution of the T2 map is established; based on the established conversion relationship, the T2 map is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes, and based on the distribution results, the pore utilization efficiency is calculated, and the drainage pressure difference range of the tight sandstone sample is determined, thereby accurately determining the sandstone drainage pressure difference range, so as to reduce the damage of the tight sandstone gas reservoir fracturing fluid according to the microscopic dynamic distribution of the sandstone gas reservoir fracturing fluid. It should be understood by those skilled in the art that the embodiments of the present invention can be provided as a method, system, or computer program product. Therefore, the present invention may take the form of an entirely hardware embodiment, an entirely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention may take the form of a computer program product embodied in one or more computer-usable storage media (including but not limited to magnetic disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0109] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowcharts and / or block diagrams, as well as combinations of processes and / or blocks in the flowcharts and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowcharts and / or block diagrams. Figure 1 a process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0110] These computer program instructions may also be stored in a computer readable memory that can direct a computer or other programmable data processing device to work in a specific manner, so that the instructions stored in the computer readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 a process or multiple processes and / or boxes Figure 1 The function specified in one or more boxes.

[0111] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operational steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing the instructions executed on the computer or other programmable device for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0112] The specific embodiments described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific embodiment of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for determining the pressure difference range of sandstone drainage, characterized in that: include: The dense sandstone sample is cut into the first section sample and the second section sample; Performing a T2 spectrum test on the first section of the sample, obtaining the T2 spectrum test results and performing inversion to determine the pore size distribution curve of the T2 spectrum; Perform mercury intrusion testing on the second section of sample, obtain the mercury intrusion test results and perform inversion to determine the mercury intrusion pore size distribution map; According to the corresponding relationship between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of mercury intrusion, a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is established; Based on the established conversion relationship, the T2 map is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes. Based on the distribution results, the pore utilization efficiency is calculated and the drainage pressure difference range of tight sandstone samples is determined to ensure that the fluid in the pores can be fully mobilized without causing additional particle migration damage and large-scale formation water production.

2. The method according to claim 1, wherein Before dividing the tight sandstone samples into the first section samples and the second section samples, the following are included: The tight sandstone samples were subjected to salt and oil washing pretreatment and aging pretreatment.

3. The method according to claim 1, wherein Acquire mercury injection test results and perform inversion, including: According to the mercury injection test results, the mercury inlet and outlet curves are obtained; The mercury injection and withdrawal curves are inverted to obtain the pore size distribution diagram of mercury injection.

4. The method according to claim 1, wherein According to the corresponding relationship between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of mercury intrusion, a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is established, including: The relaxation time and pore throat radius corresponding to the distribution frequency in the mercury injection test results are fitted, and the conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is obtained based on the fitting results.

5. The method according to claim 4, wherein The conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is obtained according to the fitting results, including: Calculate the conversion factor using the following formula: ； in, is the relaxation time, is the relaxation rate, is a constant, r is the pore radius of tight sandstone, and C is the conversion coefficient.

6. A device for determining the pressure difference range of sandstone drainage, characterized in that: include: A sample cutting module, used for cutting a dense sandstone sample into a first section sample and a second section sample; A pore size distribution curve determination module is used to perform a T2 spectrum test on the first section of samples, obtain the T2 spectrum test results and perform inversion to determine the pore size distribution curve of the T2 spectrum; A pore size distribution map determination module is used to perform a mercury injection test on the second section sample, obtain the mercury injection test results and perform inversion to determine the mercury injection pore size distribution map; A conversion relationship establishment module, for establishing a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum according to the corresponding relationship between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of mercury intrusion; The distribution result acquisition module is used to convert the T2 map into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes based on the established conversion relationship. Based on the distribution results, the pore utilization efficiency is calculated and the drainage pressure difference range of the tight sandstone sample is determined to ensure that the fluid in the pore can be fully mobilized without causing additional particle migration damage and large-scale formation water production.

7. The device according to claim 6, characterized in that Also includes sample pre-treatment modules for: Before the sample cutting module divides the dense sandstone sample into the first section sample and the second section sample, the dense sandstone sample is subjected to salt and oil washing pretreatment and aging pretreatment.

8. The device according to claim 6, wherein The pore size distribution map determination module is specifically used to: According to the mercury injection test results, the mercury inlet and outlet curves are obtained; The mercury injection and withdrawal curves are inverted to obtain the pore size distribution diagram of mercury injection.

9. The device according to claim 6, wherein The conversion relationship establishment module is specifically used for: The relaxation time and pore throat radius corresponding to the distribution frequency in the mercury injection test results are fitted, and the conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is obtained based on the fitting results.

10. The device according to claim 9, wherein The conversion relationship establishment module is specifically used for: Calculate the conversion factor using the following formula: ； in, is the relaxation time, is the relaxation rate, is a constant, r is the pore radius of tight sandstone, and C is the conversion coefficient.

11. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein: When the processor executes the computer program, the method according to any one of claims 1 to 5 is implemented.

12. A computer-readable storage medium, characterized in that The computer-readable storage medium stores a computer program, and when the computer program is executed by a processor, the method according to any one of claims 1 to 5 is implemented.

13. A computer program product, characterized in that The computer program product comprises a computer program, and when the computer program is executed by a processor, the method according to any one of claims 1 to 5 is implemented.

Images