Method and device for determining sandstone drainage and mining pressure difference range

Abstract

The invention discloses a method and a device for determining a sandstone drainage and mining pressure difference range. The method comprises the following steps: cutting a compact sandstone sample into a first section of sample and a second section of sample; performing T2 atlas testing on the first section of sample, obtaining a T2 atlas testing result, performing inversion, and determining a pore size distribution curve of a T2 atlas; performing a mercury injection test on the second-section sample, obtaining a mercury injection test result, performing inversion, and determining a mercury injection aperture distribution diagram; according to the corresponding relationship between the pore diameter distribution curve of the T2 map and the pore diameter distribution diagram of mercury injection, establishing the conversion relationship between the T2 map and the pore diameter distribution of the T2 map; according to the established conversion relation, the T2 map is converted into fracturing fluid and imbibition and / or flowback distribution results in different apertures, so that the sandstone drainage and mining pressure difference range is accurately determined, and damage to the tight sandstone gas reservoir fracturing fluid is reduced according to micro dynamic distribution of the sandstone gas reservoir fracturing fluid.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas field development, and in particular to a method and a 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 recited in the claims. No admission is made that the description herein is prior art by inclusion in this section.

[0003] As a typical unconventional natural gas resource, tight sandstone gas is of great development value. Tight sandstone gas reservoirs do not have natural production capacity, and large-scale hydraulic fracturing technology is the key and way out for the development of such gas reservoirs. Intuitively depicting the microscopic distribution of gas and water in the reservoir pores during the fracturing fluid's imbibition along the fracture surface into the matrix and the gas-driven fracturing fluid's backflow process is of great significance for the optimization of fracturing construction measures and post-fracturing backflow systems.

[0004] At present, the dynamic distribution of fracturing fluid in the reservoir during the process of fracturing fluid imbibition-flowback is mostly carried out by core-scale physical simulation experiments. Based on geological knowledge, simulating reservoir conditions, and conducting plunger or full-diameter core physical model experiments are widely used in conventional reservoir gas-water seepage research. However, for dense rocks, seepage is mainly micro-nano flow, with more complex interface effects and seepage mechanisms. Conventional experimental methods and experimental means can no longer meet the research on the microscopic distribution of dense rocks. Summary of the invention

[0005] An embodiment of the present invention provides a method for determining a sandstone drainage pressure difference range, which is used to accurately determine the sandstone drainage pressure difference range. The method includes:

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

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

[0008] Conduct mercury injection testing on the second section of the sample, obtain the mercury injection testing results and perform inversion to determine the mercury injection 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 spectrum 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 the tight sandstone sample is determined.

[0011] The embodiment of the present invention further provides a device for determining the pressure difference range of sandstone drainage, which is used to adapt to the specific conditions of tight sandstone gas reservoirs and reduce the damage of fracturing fluid in tight sandstone gas reservoirs. The device includes:

[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 pore size distribution map of the mercury injection;

[0015] A conversion relationship establishment module, 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 injection;

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

[0017] An embodiment of the present invention further provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the above-mentioned method for determining the sandstone drainage pressure difference range when executing the computer program.

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

[0020] In an embodiment of the present invention, a dense sandstone sample is cut into a first section sample and a second section sample; a T2 spectrum test is performed on the first section sample, the T2 spectrum test result is obtained and inverted, and the pore size distribution curve of the T2 spectrum is determined; a mercury injection test is performed on the second section sample, the mercury injection test result is obtained and inverted, and the pore size distribution diagram of the mercury injection is determined; according to the correspondence between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of the mercury injection, a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is established; according to the established conversion relationship, the T2 spectrum is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes, and according to the distribution results, the utilization efficiency of the pores is calculated, and the drainage pressure difference range of the dense sandstone sample is determined, thereby accurately determining the sandstone drainage pressure difference range, so as to reduce the damage of the fracturing fluid in the dense 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 use in the embodiments or the prior art descriptions. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without creative work. In the drawings:

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

[0023] Figure 2 It is a result diagram of the experimental sample design in the embodiment of the present invention;

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

[0025] Figure 4 The nuclear magnetic resonance images and cumulative permeability contribution results after gas flooding with different displacement pressure differences in the embodiment of the present invention;

[0026] Figure 5 The optimal result of the drainage pressure difference considering the pore utilization efficiency of the base block in the embodiment of the present invention;

[0027] Figure 6 This is a T2 spectrum result diagram 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] Fig. 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] Fig.10 This is a T2 spectrum result diagram of the gas drive fracturing fluid flowback process in an embodiment of the present invention;

[0032] Fig.11 This is a diagram showing the microscopic distribution of gas and water in the gas drive fracturing fluid flowback process in an embodiment of the present invention;

[0033] Fig.12 It is a 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 solution and advantages of the embodiments of the present invention more clear, the embodiments of the present invention are further described in detail below in conjunction with 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 difference range in an embodiment of the present invention, the method comprising:

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

[0037] Step 102, performing a T2 spectrum test on the first section of the sample, obtaining the T2 spectrum test result and performing inversion to determine the pore size distribution curve of the T2 spectrum;

[0038] Step 103, performing a mercury injection test on the second section of the sample, obtaining the mercury injection test results and performing inversion to determine a mercury injection pore size distribution diagram;

[0039] Step 104, 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;

[0040] Step 105, according to the established conversion relationship, the T2 spectrum is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes, and the pore production efficiency is calculated according to the distribution results 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 dense sandstone sample into a first section sample and a second section sample, the method includes:

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

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

[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 result is obtained and inverted to determine the pore size distribution curve of the T2 spectrum.

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

[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 pore size distribution diagram of the mercury injection.

[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 a specific embodiment, the saturated nuclear magnetic T2 distribution spectrum and cumulative frequency distribution spectrum of the sample in section A, and the mercury injection pore size distribution spectrum of section B are obtained. Since the pore throat structure of the core samples at the same depth and the same position is not much different, the pore size distribution curve obtained by the nuclear magnetic T2 spectrum of section A and the pore size distribution curve obtained by mercury injection of section B have a strong correspondence. By fitting the relaxation time and pore throat radius corresponding to the same cumulative distribution frequency, the conversion relationship between the nuclear magnetic 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 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 great influence 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 approximated as constants, 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, and the slope of the two is the corresponding conversion coefficient C, such as Figure 7 shown.

[0057] In step 104, a conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is established according to the corresponding relationship between the pore size distribution curve of the T2 spectrum and the pore size distribution diagram of mercury intrusion.

[0058] In one embodiment, according to the correspondence 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:

[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, the conversion relationship between the T2 spectrum and the pore size distribution of the T2 spectrum is obtained according to the fitting result, including:

[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, according to the established conversion relationship, the T2 spectrum is converted into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes, and the pore production efficiency is calculated based on the distribution results 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, from which the flow 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 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 obtained 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 point selection, φ is the porosity, %; T2 is the nuclear magnetic signal value;

[0074] The cumulative penetration rate 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] Based on the saturated water NMR spectrum, the cumulative distribution curve of permeability contribution is obtained. 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 the pores greater 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 less than 2.65ms basically do not contribute to the permeability. It can be seen that the lower limit of the drainage pressure difference at least needs to be able to mobilize the fluid in the pores greater than 99.54ms, and the upper limit of the drainage pressure difference only needs to be able to mobilize the fluid in the pores above 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 that can mobilize the fluid in the pores above 41.75ms. In addition, the pressure difference should not be pursued too large. The research results of this patent show that even if the pressure difference is adjusted to a very large value, so that the fluid in the pores below 41.75ms can be used, this part contributes less to the permeability and production capacity. On the contrary, too large a pressure difference will induce damage to particle migration and potentially induce a large amount of secondary movable water to be converted into movable water, causing problems such as early water breakthrough time of gas wells. It can be seen that obtaining these data can provide a basis for subsequent steps to determine the efficiency of base block pore throat utilization and the range of drainage pressure difference.

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

[0079]

[0080]

[0081] According to 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 the core that has completed the fracturing fluid infiltration and invasion experiment along the hydraulic fracture surface, and the gas-driven fracturing fluid is returned according to the set displacement pressure difference and displacement time, and the T2 spectrum after the displacement is completed is obtained and the gas-fracturing fluid distribution is inverted. Specifically, the above displacement pressure is 0.1-10MPa, and the experiment is gradually increased. Preferably, the displacement pressure can be differentially adjusted according to the specific physical properties of the reservoir. The displacement time is 30min, and the confining pressure should always be more than 3MPa greater than the displacement flow pressure difference to ensure the stability of the seepage.

[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 values ​​of permeability contribution 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 drive backflow at different pressure differences are as follows: Figure 4 As shown in the figure, after the displacement with a pressure difference of 0.5MPa, a large amount of fluid in the pores greater than 99.54ms is still unused. As the pressure difference increases to 2MPa, the fluid in the pores greater than 99.54ms is effectively mobilized, but there is still some fluid in the pores between 75.62ms and 99.54ms that is not mobilized. At this time, the fluid utilization efficiency in this part of the pore throat is 64.34%. The displacement pressure difference is further increased to 3MPa, and the fluid utilization efficiency in the pores between 75.62ms and 99.54ms reaches about 90%. The displacement with the pressure difference is further increased until the pressure difference reaches 8MPa. It can be seen that under the displacement with a pressure difference of 8MPa, the fluid utilization efficiency in the pores between 75.62ms and 99.54ms is increased to about 93%, and the fluid utilization efficiency in the pores between 3.65ms and 75.62ms is increased by 20.54%. The pressure difference of 3MPa has basically met the requirements of being able to mobilize the fluid in the pores without inducing additional particle migration damage and large-scale water production. If the pressure difference is greater than 3MPa, 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 3MPa is the final optimal pressure difference, and is also the optimal drainage pressure difference value 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 mine fracturing fluid formula is configured with reference to the industry standard SY / T51072016 "Water-based fracturing fluid performance evaluation method", and the properties of the fracturing fluid are tested to ensure consistency with the mine performance. The fracturing fluid infiltration and invasion process after fracturing is simulated, and the forced infiltration and invasion of the fracturing fluid is simulated under a pressure difference of 3.5MPa. The nuclear magnetic resonance T2 spectrum test is carried out at 30min, 60min, 90min, 150min, 210min, and 300min of infiltration 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 Fig. 9As shown, 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, nuclear magnetic resonance T2 spectrum tests are obtained at different times, and the conversion relationship between nuclear magnetic resonance T2 spectrum and pore size distribution is established by fitting, and the T2 spectrum is converted into the microscopic 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 gas-driven fracturing fluid backflow process after fracturing is simulated, the displacement direction is reversed, and high-purity nitrogen is used to reversely displace the core after the fracturing fluid has invaded. The nuclear magnetic resonance T2 spectrum test is carried out 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 the fracturing fluid and gas phase in pores of different sizes according to the conversion formula, and the gas-water distribution plate after the gas-driven fracturing fluid backflow at different time and space stages is obtained, such as Fig.10 and Fig.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-driven fracturing fluid flowback experiments are carried out under reservoir temperature and effective stress; nuclear magnetic resonance 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 charts after gas-driven 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. Fig.12 The device shown comprises:

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

[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 determination module 123 is used to perform a mercury injection test on the second section of the sample, obtain the mercury injection test results and perform inversion to determine the pore size distribution map of the mercury injection;

[0092] A conversion relationship establishing module 124, 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;

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

[0094] In one embodiment, a sample preprocessing module is further included, which is used to:

[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 determination 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 used 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 used 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 further provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the above-mentioned method for determining the sandstone drainage pressure difference range when executing the computer program.

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

[0108] In the embodiment of the present invention, the dense sandstone sample is cut into a first section sample and a second section sample; the first section sample is subjected to a T2 map test, the T2 map test result is obtained and inverted, and the pore size distribution curve of the T2 map is determined; the second section sample is subjected to a mercury injection test, the mercury injection test result is obtained and inverted, and the pore size distribution diagram of the mercury injection is determined; according to the corresponding relationship 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; according to the established conversion relationship, the T2 map is converted into the distribution results of the fracturing fluid and the imbibition and / or backflow in different pore sizes, and according to the distribution results, the mobilization efficiency of the pores is calculated, and the drainage pressure difference range of the dense sandstone sample is determined, thereby accurately determining the sandstone drainage pressure difference range, so as to reduce the damage of the fracturing fluid of the dense sandstone gas reservoir according to the microscopic dynamic distribution of the fracturing fluid of the sandstone gas reservoir. 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 can take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware. Moreover, the present invention can take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program codes.

[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 flowchart and / or block diagram, as well as the combination of processes and / or blocks in the flowchart and / or block diagram, 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 flowchart and / or block diagram. 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 capable of directing a computer or other programmable data processing device to operate 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 A 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 operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions 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 a first section sample and a second section sample; Performing a T2 spectrum test on the first section of the sample, obtaining the T2 spectrum test result and performing inversion to determine the pore size distribution curve of the T2 spectrum; Conduct mercury injection testing on the second section of the sample, obtain the mercury injection testing results and perform inversion to determine the mercury injection 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; According to the established conversion relationship, the T2 spectrum 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 the tight sandstone sample is determined.

2. The method according to claim 1, characterized in that Before dividing the tight sandstone samples into the first section samples and the second section samples, including: The dense sandstone samples were subjected to salt and oil washing pretreatment and aging pretreatment.

3. The method according to claim 1, characterized in that 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, characterized in that 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, characterized in that 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: 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.

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 pore size distribution map of the mercury injection; A conversion relationship establishment module, 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 injection; The distribution result acquisition module is used to convert the T2 spectrum into the distribution results of fracturing fluid and imbibition and / or flowback in different pore sizes according to the established conversion relationship.

7. The device according to claim 6, characterized in that Also included are sample pre-processing 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, characterized in that The pore size distribution map determination module is specifically used for: 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, characterized in that 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, characterized in that The conversion relationship establishment module is specifically used for: Calculate the conversion factor using the following formula: 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.

11. A computer device comprising a memory, a processor and a computer program stored in the memory and executable on the processor, characterized in that: 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.

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