Performance evaluation method and device for tight sandstone natural gas reservoir

Abstract

The invention relates to a tight sandstone natural gas reservoir performance evaluation method and device. The method comprises reservoir classification evaluation and physical property lower limit evaluation. The reservoir classification evaluation is based on a high-pressure mercury injection curve form, a wide and gentle platform type is taken as a class I reservoir, a gentle platform type is taken as a class II reservoir, and a steep platform type is taken as a class III reservoir; the physical property lower limit evaluation takes a comprehensive physical property lower limit as a reference, and the comprehensive physical property lower limit is a weighted average value of the initial physical property lower limit, the second physical property lower limit, the third physical property lower limit and the fourth physical property lower limit; wherein the initial physical property lower limit is determined based on an empirical statistical method, the second physical property lower limit is determined based on a mercury injection parametric method, the third physical property lower limit is determined based on a nuclear magnetic resonance method movable fluid saturation method, and the fourth physical property lower limit is determined based on a movable fluid minimum pore throat radius. The method solves the problems that a traditional single method is large in physical property lower limit determination deviation and incomplete in classification evaluation, and provides technical support for efficient exploration and development of tight gas reservoirs.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil and natural gas exploration and development, and specifically relates to a method and device for evaluating the performance of tight sandstone natural gas reservoirs, which is particularly suitable for tight sandstone gas reservoirs with strong heterogeneity and complex pore structure, such as the Yan'an gas field in the Ordos Basin. Background Art

[0002] As conventional oil and gas resources gradually deplete, the exploration and development of unconventional energy sources, such as tight sandstone gas, has become a global focus. The Ordos Basin is a major tight gas-rich region in China, and the Yan'an gas field reservoirs are characterized by low porosity, ultra-low permeability, strong heterogeneity, and a complex pore structure. Traditional reservoir evaluation methods have the following problems: 1. Imperfect reservoir classification and evaluation system: Existing reservoir classification standards focus on static physical parameters (porosity and permeability), ignoring the dynamic evolution of pore throats and movable fluid characteristics during the reservoir formation stage. As a result, the evaluation results cannot truly reflect the reservoir development potential. 2. Single method for determining lower limits of physical properties: Existing technologies often rely on a single method (such as empirical statistics or mercury intrusion), and the lower limits of physical properties obtained by different methods vary significantly, resulting in low credibility of the results. For example, empirical statistics are based only on macroscopic data statistics and do not consider microscopic pore structure; while mercury intrusion parameter methods can reflect pore throat characteristics, they are difficult to characterize the dynamic response of fluids; 3. Insufficient technical integration: Existing research lacks the collaborative analysis of multiple technologies such as high-pressure mercury injection, nuclear magnetic resonance, and core experiments, making it difficult to fully reveal the correlation mechanism between reservoir microscopic characteristics and macroscopic physical properties.

[0003] Combining multiple methods to determine physical property limits is a future development trend, but existing technologies have not yet formed a standardized process. Therefore, a reservoir evaluation method that integrates multiple technologies and incorporates dynamic accumulation characteristics is urgently needed. Summary of the Invention

[0004] In order to solve the above technical problems, the present invention provides a method and device for evaluating the performance of tight sandstone natural gas reservoirs. The method and device are a systematic solution that combines multiple methods to determine reservoir performance evaluation. The method is suitable for the exploration and development of tight gas reservoirs with strong heterogeneity and complex pore structure, and provides technical support for the efficient exploration and development of tight gas reservoirs.

[0005] The technical solution of the present invention is: (1) The present invention proposes a method for evaluating the performance of tight sandstone natural gas reservoirs.

[0006] A method for evaluating the performance of tight sandstone natural gas reservoirs, including reservoir classification evaluation and physical property lower limit evaluation; the method is characterized in that the reservoir classification evaluation is based on the morphology of the high-pressure mercury injection curve, with wide and gentle platform-type reservoirs as Class I, gentle platform-type reservoirs as Class II, and steep platform-type reservoirs as Class III; The evaluation of the physical property lower limit is based on the comprehensive physical property lower limit, which is the weighted average of the initial physical property lower limit, the second physical property lower limit, the third physical property lower limit and the fourth physical property lower limit; among them, the initial physical property lower limit is determined based on the empirical statistical method, the second physical property lower limit is determined based on the mercury injection parameter method, the third physical property lower limit is determined based on the nuclear magnetic resonance method and the movable fluid saturation method, and the fourth physical property lower limit is determined based on the minimum pore throat radius of the movable fluid.

[0007] In the process of determining the initial physical property lower limit, the cumulative energy storage loss boundary parameter is set to 5%, and the initial physical property lower limit is determined in combination with the frequency of the reservoir physical property production capacity loss curve; specifically, when the cumulative energy storage loss boundary parameter is set to 5%, the corresponding porosity is the initial porosity lower limit, and then the porosity lower limit cumulative distribution frequency corresponding to the initial porosity lower limit is determined. The value of the permeability lower limit cumulative distribution frequency is equal to the value of the porosity lower limit cumulative distribution frequency. Taking the permeability lower limit cumulative distribution frequency as the boundary, the corresponding permeability is the initial permeability lower limit.

[0008] The specific process of determining the second physical property lower limit is: taking the porosity inflection point appearing in the mercury injection parameter method as the second porosity lower limit, and then calculating the second permeability lower limit based on the relationship between porosity and permeability.

[0009] The specific process of determining the third physical property lower limit is to obtain the movable fluid saturation by conducting nuclear magnetic resonance saturation centrifugation experiments on core samples in the study area, and take the porosity corresponding to the movable fluid saturation of 10% as the third porosity lower limit, and the corresponding permeability as the third permeability lower limit.

[0010] The specific process for determining the lower limit of the fourth physical property is to obtain the nuclear magnetic resonance T2 cutoff value, and the pore throat radius corresponding to the nuclear magnetic resonance T2 cutoff value is the minimum pore throat radius of the movable fluid; perform a correlation analysis on the reservoir porosity, permeability and pore throat radius, and then determine the fourth porosity lower limit and the fourth permeability lower limit based on the pore throat radius limit.

[0011] The weights of the initial physical property lower limit, the second physical property lower limit, the third physical property lower limit and the fourth physical property lower limit are calculated respectively by the hierarchical analysis method, and then the comprehensive physical property lower limit is obtained by the weighted average method.

[0012] It also includes the verification of reservoir classification based on the morphology of high-pressure mercury injection curves, in combination with the main peak position of the nuclear magnetic resonance T2 spectrum and the movable fluid saturation.

[0013] It also includes, based on the verified reservoir classification results, constructing a reservoir classification evaluation table with permeability, porosity, displacement pressure, median pressure, throat radius, mercury withdrawal efficiency and movable fluid saturation as characteristic parameters.

[0014] The conversion formula between the NMR T2 cutoff value and the pore throat radius is: r=CT2 1 / n Where r is the pore throat radius, μm; T2 is the transverse relaxation time, ms; C and n are fitting parameters.

[0015] (2) The present invention proposes a device for evaluating the performance of tight sandstone natural gas reservoirs.

[0016] A device for evaluating the performance of a tight sandstone natural gas reservoir comprises a data acquisition module, a data processing module and a visualization output module connected in sequence; wherein the data processing module comprises a reservoir classification evaluation module and a physical property lower limit evaluation module; the physical property lower limit evaluation module comprises an initial physical property lower limit determination module, a second physical property lower limit determination module, a third physical property lower limit determination module and a fourth physical property lower limit determination module.

[0017] The technical effects of the present invention are: 1. The classification and evaluation system of the present invention integrates macroscopic physical properties and microstructures, meeting actual development needs; 2. This invention solves the problems of large deviation in determining the lower limit of physical properties and incomplete classification evaluation caused by traditional single methods, providing technical support for the efficient exploration and development of tight gas reservoirs; 3. The present invention improves the accuracy of determining the lower limit of physical properties by more than 30% through the collaboration of multiple methods; 4. The system of the present invention supports dynamic parameter optimization and adapts to different geological conditions of tight gas reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0018] Figure 1 This is the porosity and permeability distribution map of the tight reservoir in Yan'an gas field.

[0019] Figure 2 This is the correlation analysis diagram between porosity and permeability.

[0020] Figure 3 This is the correlation analysis diagram between reservoir permeability and pore structure parameters in the study area.

[0021] Figure 4 This is the nuclear magnetic resonance T2 spectrum distribution diagram of the Yan'an gas field core.

[0022] Figure 5 This is the characteristic diagram of the mercury injection curve in the study area.

[0023] Figure 6 It is the frequency distribution curve of permeability and porosity.

[0024] Figure 7 This is the relationship diagram between permeability, displacement pressure and median pressure.

[0025] Figure 8 This is the intersection diagram of NMR movable fluid saturation, porosity and permeability.

[0026] Figure 9 This is the conversion diagram between core NMR T2 and pore throat radius.

[0027] Figure 10 This is the relationship diagram between porosity, permeability and pore throat radius in the study area.

[0028] Figure 11 This is a weight diagram of the lower limits of physical properties determined by the four methods of the present invention. DETAILED DESCRIPTION

[0029] To make the purpose, technical solutions, and advantages of the embodiments of the present invention more clear, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0030] The present invention takes the tight sandstone reservoir of Yan'an gas field as an example to describe the method of the present invention in detail.

[0031] A method for evaluating the performance of tight sandstone natural gas reservoirs is as follows: Step 1: Collect tight sandstone core samples from the study area; obtain their porosity, permeability, high-pressure mercury injection parameters, and nuclear magnetic resonance T2 spectrum data; Tight sandstone core samples were collected from several representative wells in the He 8, Shan 1, Shan 2, and Benxi formations of the Yan'an gas field. Sixty core samples, measuring 2.5 cm in diameter and 5.0 cm in length, were cut along the bedding plane. After oil washing, the core samples were analyzed using gas permeability testing, high-pressure mercury injection, and nuclear magnetic resonance (NMR) to determine the lower limits of porosity and permeability. Porosity and permeability were determined using helium, using a WY-K100 automatic permeability meter. Nuclear magnetic resonance experiments were conducted using a laboratory centrifuge, and high-pressure mercury injection experiments were performed using an Autopore IV 9505 mercury injection instrument.

[0032] Obtain reservoir physical properties, comprehensively calculate the rock porosity and permeability data of 60 tight sandstone core samples, and calculate the distribution histogram of reservoir gas porosity and gas permeability ( Figure 1) It can be seen that the overall physical properties of the study area are relatively low. According to the industry standard "Petroleum and Natural Gas Reserve Estimation Specification" (DZ / T 0217-2020), it is judged to be a low-porosity and ultra-low-permeability reservoir. The porosity distribution range is 2.15%~17.36%, with an average of 7.29%; the permeability distribution range is 0.002~0.887mD, with an average of 0.096mD. It is a typical tight sandstone with strong heterogeneity. The porosity distribution frequency in the range of 4%~7% is the highest, accounting for 26%, followed by the range of 7%~10%, accounting for 21%, and the range of <4% has the lowest distribution frequency; the permeability is most distributed in the range of 0.01~0.05mD, accounting for 43.34%, and the distribution frequency in other intervals is relatively low. According to the intersection diagram of gas porosity and gas permeability, it can be seen that gas porosity and gas permeability show an exponential correlation ( Figure 2 ), the correlation is poor, with a correlation coefficient of only 0.185, small porosity, low permeability and strong heterogeneity.

[0033] Obtaining pore-throat structural characteristics. Microscopic pore-throat structure is an important factor in reflecting reservoir characteristics. High-pressure mercury injection (HIP) is currently the most widely used method for studying reservoir microscopic pore-throat structural characteristics. By analyzing HIP data from the study area, pore-throat structural characteristics were qualitatively and quantitatively analyzed. Comprehensive statistical data on rock porosity and permeability were collected from 24 tight sandstone core samples from different layers of the tight reservoir in the Yan'an gas field (Table 1). Displacement pressures ranged from 0.07 to 1.86 MPa, with an average of 0.85 MPa. Median pressures ranged from 0.42 to 70.33 MPa, with an average of 18.64 MPa. Median throat radii ranged from 0.01 to 1.73 μm, with an average of 0.25 μm. Maximum mercury injection saturations ranged from 71.11% to 89.39%, with an average of 82.15%. Mercury removal efficiencies ranged from 11.97% to 55.26%, with an average of 35.42.

[0034] Table 1 Statistics of core physical properties and pore structure parameters of tight reservoirs in Yan'an gas field ; Permeability has a certain negative correlation with both median pressure and displacement pressure, and the correlation between displacement pressure and permeability is higher [ Figure 3 (a) Figure 3 (b)]. As the displacement pressure of the tight sandstone core samples increases from 0 to 2.0 MPa, the permeability gradually decreases from 0.9 mD to about 0.01 mD, with a large decrease; in addition, the permeability of almost all tight sandstone core samples is lower than 1.0 mD, indicating that the reservoir in the study area has small pore throats and strong heterogeneity. There is a weak positive correlation between permeability and average pore throat radius [ Figure 3 (c) Figure 3(d)] High-quality, relatively high-permeability reservoirs with permeabilities exceeding 0.5 mD have average pore throat radii exceeding 0.1 μm. Relatively speaking, the larger the average pore throat radius of tight sandstone core samples, the greater the permeability. There is no significant correlation between permeability and throat sorting coefficient.

[0035] To obtain the movable fluid characteristics, we conducted a comprehensive nuclear magnetic resonance movable fluid analysis of 12 tight sandstone core samples from different layers of the Yan'an gas field. Figure 4 This figure shows the T2 spectrum distribution after centrifugation at an optimal centrifugal force of 2.07 MPa. As can be seen from the figure, the T2 spectrum is primarily single-peaked or weakly double-peaked, with the main peak concentrated in the short relaxation interval (<10 ms). The double-peaked, right-skewed pattern (S2-24) has its main peak located to the right of 100 ms, indicating the development of distinct macropores. The single-peaked, left-skewed pattern (H8-7) has its main peak concentrated within 10 ms, reflecting the dominance of micropores. This indicates that movable fluids in the Yan'an gas field are primarily contained in large and medium pores, while small pores are primarily bound fluids. The reservoir's microscopic pores are primarily micron- to submicron-sized, and the pore structure is highly heterogeneous.

[0036] Table 2 shows the results of nuclear magnetic resonance (NMR) movable fluid testing of reservoir cores. The table shows that the T2 cutoff values ​​for the reservoir cores range from 0.52ms to 2.84ms, with an average of 1.32ms; the irreducible fluid saturation ranges from 26.11% to 87.19%, with an average of 53.53%; and the movable fluid saturation ranges from 12.81% to 73.89%, with an average of 46.47%. The irreducible fluid saturation and movable fluid saturation show a significant negative correlation. The data indicate that the reservoir space in the Yan'an gas field cores is primarily micropores, and fluid mobility is significantly controlled by pore structure.

[0037] Table 2. Nuclear magnetic resonance movable fluid test results of Yan'an gas field cores .

[0038] Step 2: Reservoir classification and evaluation; Based on the morphology of high-pressure mercury injection curves, the reservoirs in the study area are divided into three categories: Capillary pressure curve is an important data reflecting the microscopic pore structure of the reservoir, and the microscopic pore structure of the reservoir directly controls the quality of the reservoir physical properties. Based on the mercury injection curve and its characteristic parameters, the mercury injection curves of the study area are divided into three categories: Figure 5 ). Among them, there are 9 Class I curve samples, 8 Class II curve samples, and 7 Class III curve samples; Type I curve presents a wide and gentle platform shape, with relatively uniform pore size distribution, low displacement pressure, low median pressure, good sorting, large pore throat radius and good connectivity, indicating a typical high-quality reservoir type; Type II curve presents a relatively gentle platform shape, with low displacement pressure, small median pore throat radius, low median pressure, good sorting and good connectivity, indicating a good reservoir type; Type III mercury injection curve presents a relatively steep platform shape, with high displacement pressure, large pore throat radius, high median pressure, poor sorting and poor connectivity, indicating a poor reservoir type.

[0039] Analysis of the capillary pressure curves and pore cumulative distribution curves of the samples reveals that for samples with permeabilities less than 0.1 mD, the fluid flow channels are primarily microcapillary pore throats (0.01-0.1 μm). These pore throats are very small, with displacement pressures exceeding 1.0 MPa and median pressures exceeding 10 MPa. For samples with permeabilities between 0.1 and 10.0 mD, the fluid flow channels are primarily microcapillary pore throats (0.01-0.1 μm) and capillary pore throats (0.1-1.0 μm), with low seepage resistance, displacement pressures less than 0.5 MPa, and median pressures around 2.0 MPa. For samples with medium to high permeabilities greater than 10 mD, the fluid flow channels are primarily capillary pore throats (0.1-1.0 μm) and supercapillary pore throats (>1.0 μm).

[0040] Furthermore, the mercury injection classification results were verified by the main peak position of the nuclear magnetic resonance T2 spectrum and the movable fluid saturation; Combined with nuclear magnetic resonance T2 spectroscopy ( Figure 4 ) validates the mercury injection classification: Type I reservoirs: T2 spectra exhibit a bimodal rightward shift (main peak >100 ms), movable fluid saturation >50%, and throat radius >200 nm, consistent with high throat radii (>1.0 μm) in mercury injection results. Type II reservoirs: T2 spectra exhibit a weak bimodal or unimodal rightward shift, movable fluid saturation 30%-50%, and throat radius 50-200 nm, corresponding to throat radii of 0.1-1.0 μm in mercury injection. Type III reservoirs: T2 spectra exhibit a single leftward shift (main peak <10 ms), movable fluid saturation <30%, and throat radius <50 nm, consistent with the characteristics of micropore throats (<0.1 μm) in mercury injection.

[0041] Therefore, the above-mentioned classification criteria based on the morphology of high-pressure mercury injection curves are reasonable. The above-mentioned evaluation criteria are converted into reservoir classification evaluation criteria with permeability, porosity, displacement pressure, median pressure, throat radius, mercury withdrawal efficiency and movable fluid saturation as characteristic parameters, as shown in Table 3. This provides a reference basis for the exploration and development of tight sandstone gas reservoirs in the Yan'an gas field.

[0042] Table 3 Classification standards of reservoir pore structure in the study area .

[0043] Step 3: Determine the lower limit of comprehensive physical properties.

[0044] 3.1 Determine the lower limit of initial physical properties based on empirical statistical methods; The empirical statistical method is currently a widely used method for determining the lower limit of reservoir physical properties. When the cumulative storage and permeability loss of the low-porosity and low-permeability sections of the reservoir reaches 5% of the total cumulative amount, the corresponding lower limit of the reservoir physical property can be determined by combining the frequency of the reservoir physical property capacity loss curve; According to the empirical statistical method, the frequency distribution histograms of reservoir porosity and permeability in the study area were established (see Figure 6 By calculating the cumulative porosity and permeability within the corresponding range of different physical property parameters and combining them with the cumulative energy storage loss boundary parameter, the precise lower limit of the reservoir physical property is obtained. Figure 6 When the cumulative energy storage loss in a is 5%, the corresponding abscissa porosity is 2.69%, which is the initial porosity lower limit. The corresponding porosity lower limit cumulative distribution frequency is 3.36%. Based on this, the permeability lower limit cumulative distribution frequency of 3.36% is used as the boundary, and the corresponding permeability is 0.0024mD, which is the initial permeability lower limit.

[0045] 3.2 Determine the lower limit of the second physical property by mercury intrusion parameter method; The mercury injection parameter method determines reservoir pore structure parameters, such as displacement pressure and median pressure, by injecting fluid mercury into tight reservoirs. These pressure parameters are sensitive to changes in the porosity and permeability of tight reservoirs and are primarily influenced at the microscopic level by factors such as pore throat size, fluid surface tension, and reservoir heterogeneity. Therefore, analyzing the response characteristics of different displacement pressures and median pressures to reservoir physical parameters during mercury injection can identify the lower limit of effective reservoir physical properties, which corresponds to the inflection point of the data. According to the correlation diagram ( Figure 7 ) shows that as the displacement pressure and median pressure gradually increase, the porosity gradually decreases, but the curves each have an inflection point at a porosity of 5.4%. When the porosity is greater than this value, as the median pressure and displacement pressure decrease, the porosity increases rapidly, indicating good pore throat connectivity and significantly improved seepage capacity. However, when the porosity is less than this value, as the permeability decreases, the median pressure and displacement pressure increase rapidly, indicating poor pore throat connectivity, increased capillary resistance, and the need for a higher mercury injection pressure for penetration. Based on the inflection point, the second lower porosity limit of the effective reservoir is determined to be 5.4%; based on the relationship between reservoir porosity and permeability in the study area, the corresponding lower permeability limit is 0.014mD.

[0046] 3.3 Determine the lower limit of the third physical property by the movable fluid saturation; The nuclear magnetic resonance method uses the relaxation signal generated by hydrogen nuclei in a magnetic field to characterize the pore structure, and calibrates the nuclear magnetic resonance T2 spectrum curve through high-pressure mercury injection data to obtain the nuclear magnetic resonance pore structure characteristic parameters of the sample after saturation. By conducting nuclear magnetic resonance saturation centrifugation experiments on 12 groups of core samples in the study area, the movable fluid saturation parameters were obtained. The nuclear magnetic movable fluid saturation-porosity and permeability cross-plot (see Figure 8 ) shows that the range of movable fluid saturation by nuclear magnetic resonance (NMR) is 12.81% to 73.89%, with an average of 46.5%. Movable fluid saturation is positively correlated with porosity, with a coefficient of determination of 0.2706. Based on the relationship between the two, a movable fluid saturation of 10% corresponds to a porosity of 2.31%, which is the third lower porosity limit. Movable fluid saturation is positively correlated with permeability, with a coefficient of determination of 0.394. Based on the relationship between the two, a movable fluid saturation of 10% corresponds to a permeability of 0.0022 mD, which is the third lower permeability limit.

[0047] 3.4 Determine the lower limit of the fourth physical property by the minimum pore throat radius of the movable fluid; The nuclear magnetic resonance phenomenon refers to the resonance phenomenon caused by the spin motion of the atomic nucleus and the addition of a radio frequency field of a certain frequency. Generally, during testing, the nuclear magnetic resonance instrument applies a radio frequency field of a set frequency to the fluid in the core and its pores, then removes the radio frequency field and uses the measured transverse relaxation time T2 to represent the signal change. According to the theory of nuclear magnetic resonance core analysis, the nuclear magnetic resonance transverse relaxation time T2 reflects the size of the specific surface area in the rock pores and is proportional to the pore throat radius, that is, the smaller the T2 value, the smaller the core pore throat, and the larger the T2 value, the larger the core pore throat. The relationship between the pore radius and the T2 value can be expressed as: r=CT2 1 / n (1) In order to quantitatively characterize the characteristics of movable fluids at different pore scales, the T2 value is converted in combination with mercury injection data. During high-pressure mercury injection, mercury preferentially enters the largest pores, and gradually enters smaller pores as the pressure increases. The mercury injection pore throat distribution cannot reflect the information of pores connected by throats smaller than the maximum mercury injection pressure, while the T2 spectrum when the core is saturated with water can reflect the distribution of all pore throats in the core. If the two curves are directly compared, there will be a large error. When performing calculations, only part of the T2 spectrum corresponding to the mercury injection pore throat radius distribution is selected for comparison with the mercury injection pore throat radius distribution. Figure 8As shown in Figure (a), the cumulative distribution curves of nuclear magnetic resonance T2 relaxation time and high-pressure mercury intrusion pore throat radius are plotted. In the region to the left of the dashed line (cumulative distribution frequency < SHgmax, where SHgmax is the maximum mercury intrusion saturation), when the throat radius is rt(i) at any point, the cumulative distribution frequency is S(i). Taking S = S(i), interpolation is performed on the nuclear magnetic resonance T2 cumulative distribution curve to obtain the relaxation time T2(i) when the cumulative distribution frequency is S(i). Taking the natural logarithm on both sides of Equation (1) gives: ln r = ln C + (1 / n) ln T2(2) According to the principle of linear least squares, the values of the fitting parameters C and n in Equation (2) are solved. Figure 9 This is the fitting result of the mercury intrusion throat radius and the nuclear magnetic resonance T2 value. Based on the obtained C and n, the conversion between the nuclear magnetic resonance T2 value and the pore size can be achieved. The minimum throat radius of the mobile fluid refers to the minimum throat radius when the mobile fluid in the pores of tight sandstone can flow under the action of an external force. According to the nuclear magnetic resonance mobile fluid test results, there is still some bound fluid in certain pores under the action of the optimal centrifugal force. The T2 cut-off value is the boundary value between the mobile fluid and the bound fluid reflected in the nuclear magnetic resonance experiment. Therefore, it can also be considered that the T2 cut-off value can reflect the minimum pore throat radius of the mobile fluid in the core. The main calculation method is to find a point on the T2 spectrum distribution curve saturated with simulated formation water, such that the area enclosed by the curve to its left and the coordinate axis is equal to the area enclosed by the T2 curve after centrifugation, which is the T2 cut-off value. According to the conversion relationship between the nuclear magnetic resonance T2 value and the pore size, the pore throat radius corresponding to the T2 cut-off value can be calculated, which is the minimum pore throat radius of the mobile fluid. The calculated minimum pore throat radius of the mobile fluid is 0.05 - 5.60 μm, with an average value of 0.42 μm. Perform a correlation analysis on the reservoir porosity, permeability, and pore throat radius analyzed by mercury intrusion experiments ( Figure 10 ). Taking the pore throat radius of 0.1 μm as the boundary, the lower limit of the fourth porosity in the study area is 9.26%, and the lower limit of the fourth permeability is 0.063 mD can be obtained from the figure.

[0048] 3.5 Use the analytic hierarchy process to obtain the weighted average of the initial physical property lower limit, the second physical property lower limit, the third physical property lower limit, and the fourth physical property lower limit; and then obtain the comprehensive physical property lower limit; Determining the lower limits of reservoir physical properties is a key step in studying the formation of tight sandstone natural gas in the Yan'an Gas Field, playing an important role in understanding the formation mechanism and predicting its effects. Empirical statistics, based on a large amount of actual data, can better reflect the overall characteristics of the reservoir, providing a macroscopic perspective for determining the lower limits of reservoir physical properties. The mercury injection parameter method, based on capillary force, determines the lower limits of physical properties. Because it uses actual formation rock samples, it can better reflect the lower limits of reservoir physical properties near the sampling point. Nuclear magnetic resonance (NMR) characterizes the reservoir's pore structure and fluid properties at a microscopic level, providing a more refined means for determining the lower limits of physical properties.

[0049] The initial physical property lower limit, second physical property lower limit, third physical property lower limit and fourth physical property lower limit of the tight sandstone reservoir in the Yan'an gas field during the accumulation stage determined above are shown in Table 4 below.

[0050] Table 4 Lower limits of reservoir physical properties in Yan'an Gas Field .

[0051] Since the lower limits of reservoir physical properties analyzed by different methods vary greatly, the weights of the lower limits of reservoir physical properties obtained by different methods were analyzed using the hierarchical analysis weight calculation method, and the weighted average method was used to calculate the lower limits of physical properties of the tight sandstone reservoir in the Yan'an gas field during the accumulation stage.

[0052] The AHP method measures the relative importance of each parameter to the target value by constructing an empirical judgment matrix. By calculating the eigenvalues ​​and eigenvectors of the judgment matrix, the maximum eigenvalue of the judgment matrix and its corresponding eigenvector are obtained. The solution equation for the eigenvalue and eigenvector of the judgment matrix is ​​shown in Equation (3). det(A-λI)=0 (3) Where A is the judgment matrix, where the scale of the judgment matrix is ​​[1, 2, 3, 4]. A larger value indicates that an element is more important than another element. λ is the eigenvalue. After obtaining the maximum eigenvalue, a consistency test is performed. When the consistency test result meets the requirements, the judgment matrix is ​​used. If the verification is passed, the eigenvector corresponding to the maximum eigenvalue is calculated, and the weight vector of each parameter is obtained after normalization. The consistency test is shown in formula (4); CR=CI / RI (4) CI=(λ max -n) / (n-1) (5) CI is the consistency index. CI=0 means that the judgment matrix is ​​completely consistent. The larger the CI, the more serious the inconsistency of the judgment matrix. maxis the maximum eigenvalue corresponding to the judgment matrix, n is the order of the judgment matrix, RI is the random consistency index RI obtained by Satty simulation 1000 times, when the consistency ratio CR < 0.1, it indicates that the consistency degree of the judgment matrix A is considered to be within the allowable range, and the eigenvector of A can be used to carry out the weight vector calculation; if CR ≥ 0.1, the judgment matrix A should be considered to be modified.

[0053] The differences between different methods and verification results were compared with the correlation of each research result, and the porosity and permeability judgment matrices for different analysis methods were constructed respectively (Tables 5 and 6).

[0054] Table 5 Porosity lower limit judgment matrix of different analysis methods ; Table 6 Permeability lower limit judgment matrix of different analysis methods .

[0055] The maximum eigenvalues ​​of the porosity and permeability judgment matrices of different analysis methods were calculated to be 4.031 and 4.031 respectively. The CR values ​​of the judgment matrix consistency test were calculated to be 0.012 and 0.004, both less than 0.1. The consistency test passed and the judgment matrix met the requirements. After the judgment matrix met the test criteria, the hierarchical analysis method was used to obtain the weight values ​​of the lower limits of reservoir properties determined by different methods ( Figure 11 ), and the weighted average method was used to calculate the comprehensive lower limits of reservoir physical properties in the Yan'an gas field. The lower limit of porosity is 5.95% (Table 7), and the lower limit of permeability is 0.016 mD (Table 8).

[0056] Table 7 Porosity lower limit of Yan'an gas field ; Table 8 Lower limit of permeability of Yan'an gas field .

[0057] Through the analysis and testing method of the present invention, a classification and evaluation standard for tight reservoirs was established, taking the Yan'an gas field reservoir as an example, to further understand the quality and distribution patterns of the reservoir. Combining three experiments, namely core gas porosity measurement, high-pressure mercury injection, and nuclear magnetic resonance, on the basis of tight reservoir classification and evaluation, four methods, namely empirical statistics, mercury injection parameter method, movable fluid saturation method, and movable fluid minimum pore throat radius method, were used to carry out research on the lower limits of physical properties of the tight reservoir in the Yan'an gas field during the accumulation stage. The lower limit of porosity of the tight reservoir in the Yan'an gas field was comprehensively determined to be 5.95%, and the lower limit of permeability was 0.016mD. This provides a basis for the subsequent exploration and development of tight sandstone gas in the Yan'an gas field.

[0058] The above descriptions are merely embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any equivalent structure or equivalent process transformation made using the contents of the present invention description and drawings, or directly or indirectly applied to other related system fields, are also included in the scope of protection of the present invention.

Claims

1. A method for evaluating the performance of tight sandstone natural gas reservoirs, including reservoir classification evaluation and physical property lower limit evaluation; characterized in that: Reservoir classification and evaluation are based on the morphology of high-pressure mercury injection curves. The wide and gentle platform type is classified as Class I reservoir, the gentle platform type is classified as Class II reservoir, and the steep platform type is classified as Class III reservoir. The evaluation of the physical property lower limit is based on the comprehensive physical property lower limit, which is the weighted average of the initial physical property lower limit, the second physical property lower limit, the third physical property lower limit and the fourth physical property lower limit; among them, the initial physical property lower limit is determined based on the empirical statistical method, the second physical property lower limit is determined based on the mercury injection parameter method, the third physical property lower limit is determined based on the nuclear magnetic resonance method and the movable fluid saturation method, and the fourth physical property lower limit is determined based on the minimum pore throat radius of the movable fluid.

2. The method for evaluating tight sandstone natural gas reservoir performance according to claim 1, characterized in that: In the process of determining the initial physical property lower limit, the cumulative energy storage loss boundary parameter is set to 5%, and the initial physical property lower limit is determined in combination with the frequency of the reservoir physical property production capacity loss curve; specifically, when the cumulative energy storage loss boundary parameter is set to 5%, the corresponding porosity is the initial porosity lower limit, and then the porosity lower limit cumulative distribution frequency corresponding to the initial porosity lower limit is determined. The value of the permeability lower limit cumulative distribution frequency is equal to the value of the porosity lower limit cumulative distribution frequency. Taking the permeability lower limit cumulative distribution frequency as the boundary, the corresponding permeability is the initial permeability lower limit.

3. The method for evaluating tight sandstone natural gas reservoir performance according to claim 1, characterized in that: The specific process of determining the second physical property lower limit is: taking the porosity inflection point appearing in the mercury injection parameter method as the second porosity lower limit, and then calculating the second permeability lower limit based on the relationship between porosity and permeability.

4. The method for evaluating tight sandstone natural gas reservoir performance according to claim 1, characterized in that: The specific process of determining the third physical property lower limit is to obtain the movable fluid saturation by conducting nuclear magnetic resonance saturation centrifugation experiments on core samples in the study area, and take the porosity corresponding to the movable fluid saturation of 10% as the third porosity lower limit, and the corresponding permeability as the third permeability lower limit.

5. The method for evaluating tight sandstone natural gas reservoir performance according to claim 1, characterized in that: The specific process of determining the lower limit of the fourth physical property is to obtain the nuclear magnetic resonance T2 cutoff value, and the pore throat radius corresponding to the nuclear magnetic resonance T2 cutoff value is the minimum pore throat radius of the movable fluid; The correlation between reservoir porosity, permeability and pore throat radius was analyzed, and the fourth porosity lower limit and the fourth permeability lower limit were determined according to the pore throat radius limit.

6. The method for evaluating tight sandstone natural gas reservoir performance according to claim 1, characterized in that: The specific process of determining the comprehensive physical property lower limit is: using the hierarchical analysis method to calculate the weights of the initial physical property lower limit, the second physical property lower limit, the third physical property lower limit and the fourth physical property lower limit, and then using the weighted average method to obtain the comprehensive physical property lower limit.

7. The method for evaluating tight sandstone natural gas reservoir performance according to claim 1, characterized in that: It also includes the verification of reservoir classification based on the morphology of high-pressure mercury injection curves, in combination with the main peak position of the nuclear magnetic resonance T2 spectrum and the movable fluid saturation.

8. The method for evaluating tight sandstone natural gas reservoir performance according to claim 7, characterized in that: It also includes, based on the verified reservoir classification results, constructing a reservoir classification evaluation table with permeability, porosity, displacement pressure, median pressure, throat radius, mercury withdrawal efficiency and movable fluid saturation as characteristic parameters.

9. The method for evaluating tight sandstone natural gas reservoir performance according to claim 5, characterized in that: The conversion formula between the NMR T2 cutoff value and the pore throat radius is: r=CT2 1 / n Where r is the pore throat radius, μm; T2 is the transverse relaxation time, ms; C and n are fitting parameters.

10. A device for implementing the method for evaluating tight sandstone natural gas reservoir performance according to claim 1, characterized in that: It includes a data acquisition module, a data processing module and a visualization output module connected in sequence; wherein the data processing module includes a reservoir classification evaluation module and a physical property lower limit evaluation module; the physical property lower limit evaluation module includes an initial physical property lower limit determination module, a second physical property lower limit determination module, a third physical property lower limit determination module and a fourth physical property lower limit determination module.

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