A method for inverting dynamic characteristics of multi-field coupling in-situ percolation in a compact reservoir
Patent Information
- Application Number
- CN202610954570.7
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2026-06-30
- Publication Date
- 2026-09-22
AI Technical Summary
然而，致密储层渗流速度极低，产出流体微小，极易受到测试系统“管线死体积”和分离盲区的影响，导致宏观计量严重失真，无法准确确定相渗曲线
[0007]本发明的有益效果在于：本方法摆脱了经典成熟模型等属于公知常识的先验经验束缚，通过引入由原位实测动力学边界驱动的“毛管压力动态克服系数α(Pc)”与“非线性流动特征指数m”，构建了全新的非润湿相与润湿相非对称传导积分模型。该模型能够基于宏观驱动压力的动态前沿原位精准捕捉气相启动压差Pth，实现了对致密砂岩相渗曲线系统性“压力漂移”特征的精准刻画，为高含水致密气藏产能评价提供了唯一高保真、全尺度的链式动态参数支撑。
Smart Images
Figure CN122793784A_ABST
Abstract
Description
Technical Field
[0001] This invention relates to the fields of oil and gas reservoir engineering and core physics testing technology, specifically to a dynamic characteristic inversion method for in-situ seepage in tight reservoirs using multi-field coupling. Background Technology
[0002] With the continued development of unconventional oil and gas resources, tight sandstone gas reservoirs, characterized by low porosity, extremely low permeability, small pore throats, and strong capillary forces, make it particularly important to characterize the seepage mechanism of multiphase fluids within their microporous structures. During the high water-cut development stage of tight gas reservoirs, the relative permeability of the gas and water phases and the capillary force are core input parameters for evaluating reservoir seepage characteristics, predicting production capacity, and performing historical fitting in numerical simulations. However, existing technologies have significant limitations in obtaining these two key parameters, lacking an effective dynamic correlation mechanism between experimental testing methods and physical characterization models.
[0003] In capillary force measurement, commonly used laboratory methods include mercury intrusion porosimetry, centrifugation, and semi-permeable septum method. Mercury intrusion porosimetry not only irreversibly damages the core pore structure but also fails to simulate the actual temperature, pressure, and fluid interactions within the formation. While centrifugation can use real fluids, the repeated removal of the core from the centrifuge for measurement or NMR scanning leads to inevitable redistribution of fluid within the tight core due to frequent physical transfers and pressure releases, resulting in significant measurement errors. Furthermore, while the semi-permeable septum method can establish gas-water distribution equilibrium relatively well, existing conventional devices are mostly non-in-situ designs, making it difficult to maintain a simulated formation temperature and pressure environment while simultaneously achieving real-time, accurate monitoring of the microscopic fluid occurrence and evolution within the pores. Regarding relative permeability measurement and characterization, existing steady-state or unsteady-state methods heavily rely on macroscopic volumetric measurements of the inlet and outlet fluids. However, tight reservoirs have extremely low flow velocities and produce very small amounts of fluid, making them highly susceptible to the influence of the "pipeline dead volume" and separation blind zone in the testing system, leading to severe distortion in macroscopic measurements and making it impossible to accurately determine the relative permeability curve. Furthermore, traditional relative permeability models typically assume a constant saturation of bound water, which fails to characterize the systematic deviations in the relative permeability curve of dense sandstone caused by the increase of the driving capillary pressure difference and the dynamic release of microscopic bound fluids.
[0004] In summary, existing capillary force and relative permeability testing are physically decoupled and face dual hardware testing bottlenecks: fluid redistribution errors caused by non-in-situ transfer and fluid measurement distortion caused by pipeline dead volume. Therefore, there is an urgent need to develop a comprehensive system and method that can completely eliminate the aforementioned measurement and transfer errors in a fully enclosed multi-field coupling environment, and establish in-situ a dynamic coupling relationship and parameter inversion of "driving pressure – fluid occupancy – relative permeability". Summary of the Invention
[0005] To address at least one of the aforementioned problems, this invention proposes a dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling.
[0006] The technical solution of this invention to solve the above problems is as follows: A dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling, characterized in that the method is based on an online nuclear magnetic resonance displacement experimental system, wherein the outlet end of the core holder in the online nuclear magnetic resonance displacement experimental system is provided with a selective flow guiding and isolation component, and the selective flow guiding and isolation component is hydrophilic and gas-repellent; the method includes the following steps: S1. Take a dense core and saturate it with water, and obtain the baseline T2 spectrum of the dense core under saturated water state based on the online nuclear magnetic displacement experimental system. S2. Take the dense core from S1 after it is saturated with water, carry out unsteady gas drive under preset temperature and pressure conditions, and record the unsteady gas drive data. Smooth and normalize the unsteady gas drive data to obtain the endpoint parameters. S3. Resaturate the tight core with water and place it in an online nuclear magnetic displacement experimental system for gas drive. Acquire the T2 spectrum during the gas drive process in real time. Increase the displacement pressure difference in sequence according to the first level difference. When the attenuation amplitude of the relaxation signal is observed to be no less than the first threshold, the displacement pressure difference at this time is taken as the gas phase start-up pressure difference. S4. Continue gas driving according to the preset multi-stage displacement pressure difference, from small to large, and obtain the test T2 spectrum under each stage of displacement pressure difference in real time, and regard the displacement pressure difference as capillary force. S5. Based on the integral area of the reference T2 spectrum and the test T2 spectrum, the NMR cutoff values of each pressure difference are obtained; S6. Based on capillary force, NMR cutoff value, and measured T2 spectrum, calculate the relative permeability of the gas phase and the relative permeability of the aqueous phase using the following formulas, and reconstruct and invert the relative permeability-water saturation response curves of the gas phase and the aqueous phase using the water saturation: In the formula, k rw and k rg T represents the relative permeability of the aqueous phase and the relative permeability of the gas phase, respectively; 2min and T 2max represents the minimum and maximum transverse relaxation times in the reference T2 spectrum, respectively; T2 represents the transverse relaxation time of the reference T2 spectrum. f (T2) represents the signal amplitude of the reference T2 spectrum; T 2c (P) c ) represents the NMR cutoff value; α(P c () represents the capillary pressure dynamic overcoming coefficient; P th P represents the gas phase start-up pressure difference; c This indicates capillary force.
[0007] The beneficial effects of this invention are as follows: This method breaks free from the constraints of classical mature models and other a priori experiences that belong to common knowledge, and introduces a "capillary pressure dynamic overcoming coefficient α" driven by in-situ measured dynamic boundaries. P c ")" and "nonlinear flow characteristic index" m A novel asymmetric conduction integral model for both unwetting and wetting phases was constructed. This model can accurately capture the gas-phase initiation pressure difference in situ based on the dynamic frontier of macroscopic driving pressure. P th This study achieves a precise characterization of the systematic "pressure drift" characteristics of the relative permeability curve of tight sandstone, providing the only high-fidelity, full-scale chain dynamic parameter support for the evaluation of the production capacity of high water-cut tight gas reservoirs.
[0008] Other advantages, objectives and features of the present invention will become apparent in part from the following description, and in part from those skilled in the art through study and practice of the invention. Attached Figure Description
[0009] Figure 1 This is a flowchart of the method in this embodiment; Figure 2 The T2 spectrum is the result of testing under multi-stage displacement pressure differential. Figure 3 The figures show the relative permeability-water saturation response curves of the gas phase and the relative permeability-water saturation response curves of the water phase under multi-stage displacement pressure differentials. Detailed Implementation
[0010] The specific embodiments of the present invention will be clearly and completely described below with reference to examples. Obviously, the described examples are only some embodiments of the present invention, and not all embodiments.
[0011] In the following embodiments, deep shale refers to shale buried at a depth of more than 3,500 meters. Compared with conventional shale (shale buried at a depth of less than 3,500 meters), deep shale has more complex geological conditions, more changes in geostress, and higher reservoir temperature.
[0012] like Figure 1As shown, a dynamic characteristic inversion method for in-situ seepage in tight reservoirs using multi-field coupling is presented. The method is based on an online nuclear magnetic resonance (NMR) displacement experimental system. The outlet end of the core holder in the online NMR displacement experimental system is equipped with a selective flow-guiding isolation component, which is hydrophilic and gas-repellent. The method includes the following steps: S1. Take a dense core and saturate it with water, and obtain the baseline T2 spectrum of the dense core under saturated water state based on the online nuclear magnetic displacement experimental system. S2. Take the dense core from S1 after it is saturated with water, carry out unsteady gas drive under preset temperature and pressure conditions, and record the unsteady gas drive data. Smooth and normalize the unsteady gas drive data to obtain the endpoint parameters. S3. Resaturate the tight core with water and place it in an online nuclear magnetic displacement experimental system for gas drive. Acquire the T2 spectrum during the gas drive process in real time. Increase the displacement pressure difference in sequence according to the first level difference. When the attenuation amplitude of the relaxation signal is observed to be no less than the first threshold, the displacement pressure difference at this time is taken as the gas phase start-up pressure difference. S4. Continue gas driving according to the preset multi-stage displacement pressure difference, from small to large, and obtain the test T2 spectrum under each stage of displacement pressure difference in real time, and regard the displacement pressure difference as capillary force. S5. Based on the integral area of the reference T2 spectrum and the test T2 spectrum, the NMR cutoff values of each pressure difference are obtained; S6. Based on capillary force, NMR cutoff value, and measured T2 spectrum, calculate the relative permeability of the gas phase and the relative permeability of the aqueous phase using the following formulas, and reconstruct and invert the relative permeability-water saturation response curves of the gas phase and the aqueous phase using the water saturation: In the formula, k rw and k rg T represents the relative permeability of the aqueous phase and the relative permeability of the gas phase, respectively; 2min and T 2max represents the minimum and maximum transverse relaxation times in the reference T2 spectrum, respectively; T2 represents the transverse relaxation time of the reference T2 spectrum. f (T2) represents the signal amplitude of the reference T2 spectrum; T 2c (P) c ) represents the NMR cutoff value; α( P c () represents the capillary pressure dynamic overcoming coefficient; P th P represents the gas phase start-up pressure difference; c This indicates capillary force.
[0013] In S1 of this embodiment, the overall structure of the selected online NMR displacement experimental system is the same as that of existing online NMR displacement experimental systems; both have a displacement pump for displacement, a core holder for placing the core, an NMR system for NMR detection, and a metering system for metering the produced liquid / gas. The core holder is equipped with pressure sensors at its inlet and outlet ends, or differential pressure sensors at both ends of the core holder, to detect the pressure difference during the displacement process. These are all common devices in the art, therefore their specific details will not be elaborated here. In particular, the core holder of this embodiment differs from common existing core holders in that a selective flow guiding and isolation component is detachably provided between the outlet plug of the core holder and the core. This selective flow guiding and isolation component has hydrophilic and gas-repellent characteristics, that is, it can allow water to pass through but not gas. This component belongs to the prior art. For example, high-pressure porous ceramic separators produced by Core Laboratories in the United States or Membralox series nanoscale inorganic ceramic membrane components produced by Pall Corporation can meet the requirements of this embodiment.
[0014] The method of saturating dense rock cores with water is a common method in this field. For example, the method of saturating dense rock cores with water after vacuuming is a conventional method in this field, so its specific operation will not be described in detail.
[0015] Using the S1 method, the final reference T2 spectrum is as follows: Figure 1 As shown.
[0016] In S2 of this embodiment, the preset temperature and pressure conditions refer to the temperature and pressure conditions of the target reservoir, such as reservoir temperature and reservoir pressure, or to conducting the test under specified pressure conditions. Here, pressure, in this embodiment, refers to the confining pressure of the core holder.
[0017] Meanwhile, in this step, the specific experimental operation is as follows: nitrogen gas is injected at a constant displacement rate through a displacement pump, and the injection pressure, displacement time, and cumulative water production are synchronously monitored in real time using a data acquisition system.
[0018] The specific calculation process for the endpoint parameters is as follows: S21. Extract the raw data sequence of inlet and outlet pressure difference and cumulative water production that change continuously over time during the unsteady gas-water displacement stage; S22. Scale the early time and pressure difference data in the original data sequence using a logarithmic function; S23. The entire scaled data sequence is bounded and mapped using the arctangent function, normalizing the data sequence to the numerical range of 0 to 1. High-frequency noise during the displacement process is filtered out through mathematical composite processing to achieve smooth asymptotic fitting. For fitting, a modified inverse hyperbolic tangent function, a Weibull distribution function, or a Boltzmann asymptotic growth function can be used. These functions all possess strict mathematical asymptotic boundaries and can accurately characterize the nonlinear dynamics of fluid seepage in tight reservoirs. The modified inverse hyperbolic tangent function is preferred.
[0019] S24. Extrapolate based on the asymptotic boundary of the smoothed fitting curve to calculate and extract the initial aqueous phase permeability and theoretical bound water saturation used to construct the evolution model, and use them as endpoint parameters. Specifically, take the initial displacement state (i.e., when the cumulative driving time or pressure difference variable tends to zero) as the upper boundary of the function, and extract the intercept value of the smoothed fitting curve corresponding to this state as the initial aqueous phase permeability; at the same time, calculate the mathematical limit of the smoothed fitting curve when the independent variable tends to infinity, and extract the saturation extremum corresponding to the asymptote of this limit as the theoretical bound water saturation.
[0020] In S3 of this embodiment, the main objective is to obtain the gas-phase initiation pressure difference, which refers to the pressure difference when the non-wetting gas phase breaks through the core pores. From the perspective of seepage mechanics, the horizontal axis of the T2 spectrum represents the pore size; the further to the right the horizontal axis, the larger the pores. When the gas phase, as the non-wetting phase, forcibly squeezes into the dense core, it causes the water phase to be displaced, thereby resulting in a decrease in the NMR signal.
[0021] Considering the permeability factor, the gas phase will inevitably break through the "large pores at the front edge" where capillary resistance is the least. After breaking through the large pores, the NMR signal represented by the first peak of the T2 spectrum will decrease. Therefore, in actual operation, it is not necessary to wait for the NMR signals of all peaks in the T2 spectrum to decrease.
[0022] In this embodiment, the first displacement pressure is set to 0.05 MPa. Of course, those skilled in the art can set it within the range of 0.01 to 0.1 MPa. A larger first displacement pressure results in a shorter experimental time but decreased accuracy; a smaller first displacement pressure results in higher final accuracy but a longer time. In the actual experiment, the lowest displacement pressure, such as 0.05 MPa, is used as the displacement pressure. During the displacement process, NMR scanning is continuously performed. After the obtained T2 spectrum stabilizes, the difference between the stabilized T2 spectrum and the reference T2 spectrum is calculated: η = (T 2,0 -T 2,1 ) / T 2,0 *100%, where η represents the attenuation amplitude; T 2,0 This represents the area integral of the first peak in the reference T2 spectrum; T2,1 This represents the area integral of the first peak of each stable T2 spectrum. If the attenuation is less than the first threshold, the displacement pressure difference is increased according to the first level difference, and the above operation is repeated until the final calculated attenuation is not less than the first threshold.
[0023] The first threshold can also be set according to the actual situation. For example, in the actual design process of the first threshold, the error of the nuclear magnetic resonance spectrometer and the error of the pressure sensor need to be considered. If the error of the aforementioned equipment is large, the first threshold can be set larger. If the error of the aforementioned equipment is small, the first threshold can be set smaller. However, it is usually around 4 to 8%, preferably 5%.
[0024] In S4 of this embodiment, the so-called preset multi-stage displacement pressure difference refers to setting a series of displacement pressure differences based on the actual reservoir injection pressure. These pressure differences are usually set from small to large, and as the displacement pressure difference increases, the range between adjacent displacement pressure differences increases.
[0025] In this embodiment, the displacement pressure differentials are set to 0.5, 2, 4, 8, and 12 MPa in ascending order, and the resulting T2 spectra are as follows. Figure 2 As shown.
[0026] In S5 of this embodiment, the following sub-steps are included: performing full-spectrum area integration on the test T2 spectrum of any level of displacement pressure difference to obtain the first integrated area; performing area integration on the reference T2 spectrum from left to right; stopping the integration when the area integration of the reference T2 spectrum reaches the first integrated area, and taking the T2 value corresponding to the stopping point as the NMR cutoff value of the displacement pressure difference at that level.
[0027] In S6 of this embodiment, during actual operation, the endpoint parameters obtained in step S2, namely the initial water phase permeability and the theoretical bound water saturation, are first used as the constraint boundary. Combined with the least squares optimization algorithm, the nonlinear integral model in S6 is subjected to parameter inversion fitting, so that the error between the model calculation result (i.e., water phase permeability) and the macroscopic experimental endpoint (i.e., initial water phase permeability) is minimized, thereby accurately locking the values of λ and m specific to this core.
[0028] After obtaining the above model, the data from each test T2 spectrum are substituted into the model for calculation to obtain the relative permeability of the gas phase and the relative permeability of the water phase under each displacement pressure difference condition. The water saturation under each displacement pressure difference condition can be calculated as follows: Integrate the area of the test T2 spectrum under each displacement pressure difference condition to obtain the first area, and simultaneously integrate the area of the reference T2 spectrum to obtain the second area. The water saturation under each displacement pressure difference condition = first area / second area * 100%.
[0029] After obtaining the relative permeability of the gas phase, the relative permeability of the aqueous phase, and the water saturation under each displacement pressure differential condition, discrete numerical points of the relative permeability of the gas phase and the aqueous phase under different water saturation conditions were obtained. These discrete numerical points were then smoothed to obtain the gas phase relative permeability-water saturation response curve and the aqueous phase relative permeability-water saturation response curve. The final results are as follows: Figure 3 As shown.
[0030] In practice, to gain a thorough understanding of tight core samples, basic physical properties are typically measured upon acquisition, such as the absolute permeability. Therefore, by obtaining this absolute permeability and combining it with the relative permeability obtained in this embodiment, the actual permeability under each water saturation condition can be calculated, further providing data for reservoir research.
[0031] The present invention has been disclosed above with preferred embodiments. However, those skilled in the art should understand that these embodiments are only for describing the present invention and should not be construed as limiting the scope of the present invention. Further improvements can be made without departing from the principles of the present invention, and these improvements should also be considered within the scope of protection of the present invention.
Claims
1. A method for dynamic characteristic inversion of in-situ seepage in tight reservoirs using multi-field coupling, characterized in that, The method is based on an online nuclear magnetic resonance displacement experimental system, wherein the outlet end of the core holder in the online nuclear magnetic resonance displacement experimental system is equipped with a selective flow guiding and isolation component, which is hydrophilic and gas-repellent; the method includes the following steps: S1. Take a dense core and saturate it with water, and obtain the baseline T2 spectrum of the dense core under saturated water state based on the online nuclear magnetic displacement experimental system. S2. Take the dense core from S1 after it is saturated with water, carry out unsteady gas drive under preset temperature and pressure conditions, and record the unsteady gas drive data. Smooth and normalize the unsteady gas drive data to obtain the endpoint parameters. S3. Resaturate the tight core with water and place it in an online nuclear magnetic displacement experimental system for gas drive. Acquire the T2 spectrum during the gas drive process in real time. Increase the displacement pressure difference in sequence according to the first level difference. When the attenuation amplitude of the relaxation signal is observed to be no less than the first threshold, the displacement pressure difference at this time is taken as the gas phase start-up pressure difference. S4. Continue gas driving according to the preset multi-stage displacement pressure difference, from small to large, and obtain the test T2 spectrum under each stage of displacement pressure difference in real time, and regard the displacement pressure difference as capillary force. S5. Based on the integral area of the reference T2 spectrum and the test T2 spectrum, the NMR cutoff values of each pressure difference are obtained; S6. Based on capillary force, NMR cutoff value, and measured T2 spectrum, calculate the relative permeability of the gas phase and the relative permeability of the aqueous phase using the following formulas, and reconstruct and invert the relative permeability-water saturation response curves of the gas phase and the aqueous phase using the water saturation: In the formula, k rw and k rg T represents the relative permeability of the aqueous phase and the relative permeability of the gas phase, respectively; 2min and T 2max represents the minimum and maximum transverse relaxation times in the reference T2 spectrum, respectively; T2 represents the transverse relaxation time of the reference T2 spectrum. f (T2) represents the signal amplitude of the reference T2 spectrum; T 2c (P) c ) represents the NMR cutoff value; α( P c () represents the capillary pressure dynamic overcoming coefficient; P th P represents the gas phase start-up pressure difference; c This indicates capillary force.
2. The dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling according to claim 1, characterized in that, In S2, the unsteady gas drive data includes injection pressure, displacement time, and cumulative water production.
3. The dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling according to claim 1, characterized in that, In S2, the method for obtaining endpoint parameters includes the following steps: S21. Extract the raw data sequence of inlet and outlet pressure difference and cumulative water production that change continuously over time during the unsteady gas-water displacement stage; S22. Scale the early time and pressure difference data in the original data sequence using a logarithmic function; S23. The arctangent function is used to perform bounded constraint mapping on the scaled data sequence, normalize the data sequence to the numerical range of 0 to 1, and filter out high-frequency noise in the displacement process through mathematical composite processing to achieve smooth asymptotic fitting. S24. Extrapolate based on the asymptotic boundary of the smooth fitting curve, calculate and extract the initial water phase permeability and theoretical bound water saturation used to construct the evolution model, and use them as endpoint parameters.
4. The dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling according to claim 1, characterized in that, In S3, the first level difference is 0.05 MPa, and the first threshold is 5%.
5. The dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling according to claim 1, characterized in that, In S3, the relaxation signal refers to the peak area integral of the rightmost peak in the T2 spectrum.
6. The dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling according to claim 1, characterized in that, In S4, among the preset multi-stage displacement pressure differences, as the pressure difference increases, the range of the displacement pressure differences between adjacent stages increases.
7. The dynamic characteristic inversion method for in-situ seepage in tight reservoirs with multi-field coupling according to claim 1, characterized in that, S5 includes the following steps: The full-spectrum area of the test T2 spectrum of any displacement pressure difference is integrated to obtain the first integrated area; the area of the reference T2 spectrum is integrated from left to right. When the area integration of the reference T2 spectrum reaches the first integrated area, the integration is stopped, and the T2 value corresponding to the stop point is taken as the NMR cutoff value of the displacement pressure difference at that stage.