Method for determining permeability of fractured-vuggy reservoir

Abstract

The invention provides a fracture-vug type reservoir permeability determination method, and relates to the field of fracture-vug type reservoir physical property prediction.The fracture-vug type reservoir permeability determination method comprises the following steps that (1) theoretical models of absolute permeability, porosity, diameter and karst background of a karst cave phase, a pore phase and a fracture phase in a fracture-vug type reservoir are established; (2) a tracing method is adopted, and a target well group is tested in the fracture-cavity oil reservoir; 3) calculating the average flow velocity of the tracer in the fracture-cavity oil reservoir according to the migration linear distance of the tracer and the breakthrough time of the target well group; 4) establishing a numerical model of the target well group through a numerical model test; and 5) determining a correlation coefficient by setting permeability values of a pore phase, a fracture phase and a karst cave phase until the simulated breakthrough time of the tracer agent is equal to the actual breakthrough time. The method provided by the invention can effectively predict the permeability of different split phases of holes, fractures and holes in other areas in the same fracture-cavity oil reservoir, and has a good application prospect.

Description

Technical Field

[0001] This invention relates to the field of reservoir property prediction for fractured-vuggy oil reservoirs, and specifically to a method for determining the permeability of fractured-vuggy oil reservoirs. Background Technology

[0002] Existing methods for calculating permeability in fractured-vuggy reservoirs primarily rely on seismic analysis, core analysis, well logging, and well testing. Seismic analysis, based on the theory of seismic wave propagation in two-phase media, establishes the relationship between seismic records and the physical parameters of the two-phase medium. Since permeability and seismic properties exhibit a multivalued functional relationship, the RoughSet (RS) theory can be used to identify seismic properties closely related to permeability, obtaining optimized property combinations, which can then be trained using neural networks. This training result can be used to classify patterns of selected seismic properties in un-drilled areas, and finally, a function approximation method can be used to predict permeability. Geophysical logging is performed on almost all wells, making it the easiest method to obtain data. Therefore, using well logging data to obtain permeability is a major research area. The main methods include empirical methods (such as the Archie formula), nuclear magnetic resonance (NML) logging, and geochemical logging (GLT). Geochemical logging is less commonly used due to the special structure of fractured-vuggy reservoirs, mainly applicable to some highly filled caverns. Well testing, based on seepage mechanics to study the characteristics of oil, gas, and water layers, is often used to determine permeability. The calculation requires understanding the thickness of the formation affected by the disturbance, typically through open-hole logging. If inconsistencies exist, a production pressure drop profile is obtained for correction. After obtaining the flow profile information, the instantaneous diffusion equation for the pressure drop can be solved, and the average permeability can be calculated by plotting the Pbhf-logt curve.

[0003] Existing technologies, such as patent CN109505591A, disclose a method and system for determining the permeability limit of unfilled vugs in fractured-vuggy reservoirs. The method includes: obtaining the seepage velocity based on crude oil density, water density, and crude oil viscosity; obtaining the flow scale based on oil-water separation and the seepage velocity achieved at a vertical grid scale within one reporting step; and converting the flow scale to an equivalent vertical grid scale to obtain a graph showing the relationship between the vug permeability limit and the vertical grid step size. This method applies Darcy's flow theory to determine the lower limit of unfilled vug permeability, providing a basis for three-dimensional geological modeling and numerical simulation of fractured-vuggy reservoirs.

[0004] For example, the literature: Wang Zisheng, Ren Aijun, Yao Jun, et al. Determining the effective thickness and permeability of fractured-vuggy reservoirs using dynamic data [J]. Xinjiang Petroleum Geology, 2010(1):157-168. This mainly discusses how to use dynamic data to determine the effective thickness and permeability of fractured-vuggy reservoirs. The content includes the source and processing method of dynamic data, as well as how to estimate the effective thickness and permeability through mathematical models or algorithms. The practical application and accuracy of these methods will also be discussed, and compared with traditional static data methods. The goal is to provide oilfield engineers with a new method for more accurately assessing the development potential of reservoirs. In addition, the literature: Wei Shuaishuai, Shen Jinsong, Yang Wuyang, et al. Finite difference calculation method for equivalent permeability of fractured-vuggy porous media based on microstructure information [J]. Geophysical and Geochemical Exploration Computing Technology, 2020, 42(2):87-89. This discloses a finite difference calculation method for equivalent permeability of fractured-vuggy porous media based on microstructure information. The article details a new method for simulating and calculating the permeability of slotted porous media using microstructure information, which overcomes the limitations of traditional methods in this field and improves the accuracy and efficiency of equivalent permeability calculation.

[0005] Due to the unique characteristics of fractured-vuggy reservoirs, there is currently no specific method for predicting and calculating the permeability of each phase (pore, fracture, and cavity) within these reservoirs. Methods using seismic analysis, physical logging, and well testing only calculate the vertical distribution of permeability near a single well or the overall permeability value representing the surrounding reservoir. Therefore, it is necessary to develop a method for determining the permeability of different phases (pore, fracture, and cavity) in fractured-vuggy reservoirs to predict the permeability of other pores, fractures, and cavities in the target block. Summary of the Invention

[0006] To address the challenge of determining the permeability of different phases (pores, fractures, and cavities) in fractured-vuggy reservoirs, this invention provides a method for determining the permeability of such reservoirs. It establishes a theoretical process based on tracer testing, seismic interpretation, and flow equations to determine the relationship between fracture / cavity size, porosity, karst properties, and permeability. This invention constructs theoretical equations for the size, porosity, and permeability of the pores, fractures, and cavities in fractured-vuggy reservoirs, further highlighting the permeability characteristics of different phases in fractured-vuggy reservoirs and improving the prediction accuracy of phase permeability in similar fractured-vuggy reservoirs.

[0007] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0008] This invention provides a method for determining the permeability of fractured-vuggy reservoirs, comprising the following steps:

[0009] 1) Establish a theoretical model for the absolute permeability, porosity, diameter, and karst background of the three phases (cavitation facies, porosity facies, and fracture facies) in fractured-vuggy reservoirs:

[0010] Cave facies:

[0011]

[0012] Porous phase:

[0013]

[0014] Fracture phase:

[0015]

[0016] Where, k c k p k f The absolute permeability, in m, represents the permeability of the cave phase, porous phase, and fracture phase, respectively. c m p m f These are the overall correlation coefficients for the cave facies, porous facies, and fracture facies, respectively, a c a p a f b represents the porosity correlation coefficient for the cavernous phase, porous phase, and fracture phase, respectively. c b p b f c represents the diameter correlation coefficient for the cavernous phase, porous phase, and fracture phase, respectively. c c p c f The correlation coefficients of karst background for cave facies, porous facies, and fracture facies are respectively, where Φ is porosity and d is the karst background correlation coefficient. c The diameter;

[0017] 2) The tracing method was used to test the target well group in the fractured-vuggy reservoir;

[0018] 3) Calculate the average flow velocity of the tracer in the fractured-vuggy reservoir by using the straight-line distance of tracer migration and the breakthrough time of the target well group;

[0019] 4) Establish a numerical model of the target well group through numerical model experiments;

[0020] 5) By setting the permeability values ​​of the pore phase, fracture phase, and karst phase until the tracer's simulated breakthrough time equals the actual breakthrough time, the overall correlation coefficient, porosity correlation coefficient, diameter correlation coefficient, and lava background correlation coefficient in the theoretical model are determined.

[0021] Furthermore, the test well group described in step 2) must meet the following requirements:

[0022] ① The breakthrough time for tracers is 1-48 hours;

[0023] ② The pathway of tracer transport is clearly defined;

[0024] ③The karst background has a direct connection.

[0025] Furthermore, step 4) specifically includes establishing the numerical model of the target well group:

[0026] The relationship between flow velocity and absolute permeability is determined based on Darcy's formula:

[0027]

[0028] Among them, u x k is the sum of the migration rates of the tracer in different phases. x Φ represents the absolute permeability along the tracer's path; Φ represents porosity; x represents the distance along the x-axis (in meters); μ represents viscosity (in cP); and qt represents flow rate (in cubic meters per second). 3 / s); Ax is the cross-sectional area along the x-axis (unit: m²). 2 ); β c This is the unit conversion factor between metric and imperial units, specifically 1.127.

[0029] Furthermore,

[0030]

[0031] Where s1, s2, and s3 represent the migration paths of the tracer in the porous phase, fracture phase, and cavern phase, respectively. It is worth noting that the migration paths here are also the paths (lengths) through which the flow occurs.

[0032] Furthermore, the correlation coefficients in the theoretical model described in step 5) are determined using the curve regression method.

[0033] In some specific implementations, the overall correlation coefficient of the karst phase in step 1) is 0.000036, the overall correlation coefficient of the pore phase is 153.36, and the overall correlation coefficient of the fracture phase is 26.26.

[0034] In some specific implementations, the porosity correlation coefficient of the karst phase in step 1) is 0.326, the porosity correlation coefficient of the porous phase is 0.257, and the porosity correlation coefficient of the fracture phase is 0.569.

[0035] In some specific implementations, the diameter correlation coefficient of the cave phase in step 1) is 0.1125, the diameter correlation coefficient of the pore phase is 0.2654, and the diameter correlation coefficient of the fracture phase is 1.3625.

[0036] In some specific implementations, the lava background correlation coefficient of the cave facies in step 1) is 0.2695, the lava background correlation coefficient of the porous facies is 0.2644, and the lava background correlation coefficient of the fracture facies is 0.0645.

[0037] In some specific embodiments, the tracer is a BY-3 type fluorescent tracer.

[0038] The technical effects achieved by this invention are:

[0039] (1) This invention establishes the correlation between the permeability of different phases and their porosity, size and karst background for fractured-vuggy reservoirs, which can be applied to the permeability prediction of other areas in the same reservoir.

[0040] (2) The present invention determines the migration velocity by the path and time of tracer migration, and then uses Darcy's law to determine the permeability value of different phases. This method is relatively reliable from both a physical principle and an engineering perspective. Attached Figure Description

[0041] Figure 1 This is a tracer transport path diagram, where TK620 and TK650 are well numbers from the test wells.

[0042] Figure 2 The test graphs show different permeability values, where (a) is when k = 152, (b) is when k = 167, (c) is when k = 186, and (d) is when k = 203. Detailed Implementation

[0043] The following specific examples illustrate the implementation of the present invention. Those skilled in the art can easily understand other advantages and effects of the present invention from the content disclosed in this specification. The present invention can also be implemented or applied through other different specific embodiments, and various details in this specification can also be modified or changed based on different viewpoints and applications without departing from the spirit of the present invention.

[0044] Before further describing specific embodiments of the present invention, it should be understood that the scope of protection of the present invention is not limited to the specific embodiments described below; it should also be understood that the terminology used in the embodiments of the present invention is for describing specific embodiments and not for limiting the scope of protection of the present invention.

[0045] When numerical ranges are given in the embodiments, it should be understood that, unless otherwise stated in the invention, both endpoints of each numerical range and any value between the two endpoints may be selected. Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0046] Example 1

[0047] A method for determining the permeability of fractured-vuggy reservoirs includes the following steps:

[0048] 1) Establish a theoretical model for the absolute permeability, porosity, diameter, and karst background of the three phases (cavitation facies, porosity facies, and fracture facies) in fractured-vuggy reservoirs:

[0049] Cave facies:

[0050]

[0051] Porous phase:

[0052]

[0053] Fracture phase:

[0054]

[0055] Where, k c k p k f The absolute permeability, in m, represents the permeability of the cave phase, porous phase, and fracture phase, respectively. c m p m f These are the overall correlation coefficients for the cave facies, porous facies, and fracture facies, respectively, a c a p a f b represents the porosity correlation coefficient for the cavernous phase, porous phase, and fracture phase, respectively. c b p b f c represents the diameter correlation coefficient for the cavernous phase, porous phase, and fracture phase, respectively. c c p c f The correlation coefficients of karst background for cave facies, porous facies, and fracture facies are respectively, where Φ is porosity and d is the karst background correlation coefficient. c The diameter;

[0056] 2) The tracing method was used to test the target well group in the fractured-vuggy reservoir;

[0057] 3) Calculate the average flow velocity of the tracer in the fractured-vuggy reservoir by using the straight-line distance of tracer migration and the breakthrough time of the target well group;

[0058] Specifically, Figure 1 This shows well TK650 in the Tarim River area, where the breakthrough path of the BY-3 fluorescent tracer is relatively clear, and the straight-line distance of migration (S) is shown. min =572m) and the breakthrough time of the target well group (V ave The total seepage velocity of the tracer was calculated to be approximately 18.45 m / day.

[0059] Table 1

[0060]

[0061]

[0062] 4) Establish a numerical model of the target well group through numerical model experiments;

[0063] The relationship between flow velocity and absolute permeability is determined based on Darcy's formula:

[0064]

[0065] Among them, u x k is the sum of the migration rates of the tracer in different phases. x Φ is the absolute permeability along the tracer's path; Φ is the porosity; x is the distance along the x-axis; μ is the viscosity; qt is the flow rate; Ax is the cross-sectional area along the x-axis; β c This is the unit conversion factor between metric and imperial units, specifically 1.127.

[0066]

[0067] S1, S2, and S3 represent the migration paths of the tracer in the porous phase, fracture phase, and cavern phase, respectively.

[0068] 5) By setting the permeability values ​​for the porous phase, fracture phase, and karst phase until the simulated breakthrough time of the tracer equals the actual breakthrough time, the overall correlation coefficient, porosity correlation coefficient, diameter correlation coefficient, and lava background correlation coefficient in the theoretical model are determined using curve regression:

[0069] Specifically, Figure 2 Numerical experiments were conducted along the route of the tracer transport, assigning different permeability values ​​to different phases (i.e., k=152, k=167, k=186, k=203) to make the total flow velocity equal.

[0070] Specifically, we obtain the following formula:

[0071]

[0072]

[0073]

[0074] Finally, it should be noted that the above content is only used to illustrate the technical solution of the present invention, and is not intended to limit the scope of protection of the present invention. Simple modifications or equivalent substitutions made by those skilled in the art to the technical solution of the present invention do not depart from the essence and scope of the technical solution of the present invention.

Claims

1. A method for determining the permeability of fractured-vuggy reservoirs, characterized in that: Includes the following steps: 1) Establish a theoretical model for the absolute permeability, porosity, diameter, and karst background of the three phases (cavitation facies, porosity facies, and fracture facies) in fractured-vuggy reservoirs: Cave facies: Porous phase: Fracture phase: Where, k c k p k f The absolute permeability, in m, represents the permeability of the cave phase, porous phase, and fracture phase, respectively. c m p m f These are the overall correlation coefficients for the cave facies, porous facies, and fracture facies, respectively, a c a p a f b represents the porosity correlation coefficient for the cavernous phase, porous phase, and fracture phase, respectively. c b p b f c represents the diameter correlation coefficient for the cavernous phase, porous phase, and fracture phase, respectively. c c p c f The correlation coefficients of karst background for cave facies, porous facies, and fracture facies are respectively, where Φ is porosity and d is the karst background correlation coefficient. c The diameter; 2) The tracing method was used to test the target well group in the fractured-vuggy reservoir; 3) Calculate the average flow velocity of the tracer in the fractured-vuggy reservoir by using the straight-line distance of tracer migration and the breakthrough time of the target well group; 4) Establish a numerical model of the target well group through numerical model experiments; 5) By setting the permeability values ​​of the pore phase, fracture phase, and karst phase until the tracer's simulated breakthrough time equals the actual breakthrough time, the overall correlation coefficient, porosity correlation coefficient, diameter correlation coefficient, and lava background correlation coefficient in the theoretical model are determined.

2. The method for determining the permeability of fractured-vuggy reservoirs according to claim 1, characterized in that: The target well group mentioned in step 2) must meet the following requirements: ① The breakthrough time for tracers is 1-48 hours; ② The pathway of tracer transport is clearly defined; ③The karst background has a direct connection.

3. The method for determining the permeability of fractured-vuggy reservoirs according to claim 1, characterized in that: Step 4) describes the establishment of a numerical model for the target well group, which specifically includes: The relationship between flow velocity and absolute permeability is determined based on Darcy's formula: Among them, u x k is the sum of the migration rates of the tracer in different phases. x Φ is the absolute permeability along the tracer's path; Φ is the porosity; x is the distance along the x-axis; μ is the viscosity; qt is the flow rate; Ax is the cross-sectional area along the x-axis; β c This is the unit conversion factor between metric and imperial units, specifically 1.

127.

4. The method for determining the permeability of fractured-vuggy reservoirs according to claim 3, characterized in that: S1, S2, and S3 represent the migration paths of the tracer in the porous phase, fracture phase, and cavern phase, respectively.

5. The method for determining the permeability of fractured-vuggy reservoirs according to claim 1, characterized in that: The correlation coefficients in the theoretical model described in step 5) are determined using the curve regression method.

6. The method for determining the permeability of fractured-vuggy reservoirs according to claim 1, characterized in that: The overall correlation coefficient of the karst phase described in step 1) is 0.000036, the overall correlation coefficient of the pore phase is 153.36, and the overall correlation coefficient of the fracture phase is 26.

26.

7. The method for determining the permeability of fractured-vuggy reservoirs according to claim 1, characterized in that: The porosity correlation coefficient of the karst phase in step 1) is 0.326, the porosity correlation coefficient of the porous phase is 0.257, and the porosity correlation coefficient of the fracture phase is 0.

569.

8. The method for determining the permeability of fractured-vuggy reservoirs according to claim 1, characterized in that: The diameter correlation coefficient of the cave phase in step 1) is 0.1125, the diameter correlation coefficient of the pore phase is 0.2654, and the diameter correlation coefficient of the fracture phase is 1.3625.

9. The method for determining the permeability of fractured-vuggy reservoirs according to claim 1, characterized in that: The lava background correlation coefficient for the cave facies described in step 1) is 0.2695, the lava background correlation coefficient for the porous facies is 0.2644, and the lava background correlation coefficient for the fracture facies is 0.0645.

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