A method for determining different scale fracture-cavity property parameters in gas reservoirs

Abstract

The present application relates to a kind of method for determining different scale fracture-cavity property parameters in gas reservoir, according to the understanding of a certain gas reservoir, establish a new reservoir structure physical model;Based on pipe flow theory, establish pipe flow equation;Establish the percolation-free flow-pipe flow coupling mathematical model of "microfracture / channel big fracture / cave" type reservoir and solve, get the wellbore pressure solution function in Laplace space;Using the wellbore pressure solution obtained in Laplace space, the wellbore pressure solution in real space is obtained by programming in MATLAB software through the improved Stehfest numerical inversion method and the real space well test theoretical curve is drawn, the parameter group sensitivity analysis of well test theoretical curve is carried out, the physical property parameters of fracture-cavity actual reservoir are obtained by analyzing theoretical curve.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field exploration and development, and specifically relates to a method for determining the physical property parameters of fractures and cavities at different scales in gas reservoirs. Background Technology

[0002] In carbonate rock karst weathering crust, there is often a type of deep-buried fracture-vuggy reservoir that has undergone karst transformation. For example, the Ordovician carbonate rocks in the northern Tarim Basin are heterogeneous reservoirs composed of pores, cavities, and fractures formed by multiple phases of paleokarst karstification and subsequent tectonic alteration. The reservoirs have complex combination characteristics with varying sizes, irregular spatial distribution, and different filling properties. After testing, these fracture-vuggy reservoirs of different scales have multiple types of seismic reflection response characteristics, showing different reflection modes such as chaotic-blank and beaded.

[0003] These types of fractures generally contain a large amount of usable gas reservoir gas. Gas reservoir gas refers to a commercially valuable individual natural gas accumulation in a trap, especially a large non-associated gas reservoir (field). Some gas reservoir gas can also exist in oil and gas fields, maintaining a certain distance from the oil or oil and gas reservoir in the vertical direction.

[0004] To better locate and collect gas reservoir gas in fractures and cavities, it is generally necessary to determine the physical property parameters of fractures and cavities at different scales. The physical property parameters are mainly data on whether the material can meet the requirements in terms of manufacturing. Different materials have different physical property parameters. For example, nylon has many data requirements, such as impact strength, tensile strength, melt index, etc.

[0005] Targeting fracture-vuggy reservoirs with different reflection modes, a series of seismic prediction and description technologies for fracture-vuggy reservoirs at different scales were developed by decomposing different characteristic signals of the seismic wave field. The prediction example in Tahe Oilfield reveals that it can effectively detect the spatial distribution characteristics of reservoirs controlled by different genesis, with different development scales and different types, and finely describe the spatial longitudinal and transverse superposition relationship of pores, cavities and fractures on residual hills, so as to realize the understanding of the spatial distribution law of complex reservoirs and the accurate location of fractures and cavities.

[0006] However, the difficulty in determining the physical parameters of fractured-vuggy reservoirs with multi-scale fractured-vuggy structures lies in the flow description within these systems. Extensive research has been conducted by scholars both domestically and internationally on mathematical models of flow in fractured-vuggy carbonate oil and gas reservoirs, establishing dual-medium, triple-medium, and multi-medium well-testing models. However, these models are all based on the assumption of a continuous homogeneous seepage field, failing to realistically simulate the flow characteristics of discontinuous media and thus unable to solve the complex flow problems in multi-scale fractured-vuggy carbonate oil and gas reservoirs. Mathematical models of different fractured-vuggy structures have been established for well-testing problems in large-scale fractured-vuggy oil and gas reservoirs, such as models of wells encountering a single large cavern and models of wells encountering multiple fractured-vuggy units. However, these models have not established multi-fractured-vuggy systems where fluids exhibit three different flow exchange mechanisms—free flow, pipe flow, and seepage—among large caverns, large fractured channels, and microfractures. Furthermore, the description of different flow patterns of fluids within the medium is not yet comprehensive.

[0007] For example, in the prior art, Chinese invention patent document CN110984973A, published on April 10, 2020, entitled "Method for Determining the Controlled Reserves of a Single Well in a Fractured-Vuggy Carbonate Gas Reservoir," discloses a method for evaluating the controlled reserves of a single well in a large-scale fractured-vuggy carbonate gas reservoir. This method includes the following steps: 1. Establishing a well test model based on the combination relationship of fractures, caverns, and wellbore in a large-scale fractured-vuggy carbonate gas reservoir and the measurement parameters of these three elements; 2. Performing a Laplace transform on the well test model and solving it to obtain the bottom-hole pressure solution function in Laplace space. Then, programming and using numerical inversion techniques to obtain the actual bottom-hole pressure solution function, and simultaneously programming to obtain theoretical bottom-hole pressure data and plotting a theoretical curve; 3. Fitting the actual bottom-hole pressure solution function with the measured bottom-hole pressure data on the theoretical curve to obtain relevant data; 4. Using the well test model to fit the relevant data obtained in step 3 to obtain the volumes of two caverns and the scales of two fractures, and then using the volumetric method to determine the controlled reserves of a single well. The existing technology can accurately predict and evaluate the reserves of gas reservoirs in the early stages.

[0008] However, considering the reservoir characteristics of multi-scale fractured-vuggy carbonate gas reservoirs in the study area and taking into account the limitations of current methods, it is urgent to establish a new multi-scale multi-fractured-vuggy system structural physical model based on the division of the reservoir fractured-vuggy connection structure. Although the existing technical solutions can achieve computational monitoring of the gas reservoir, they cannot effectively utilize seepage relations, pipe flow theory, and cavern free flow theory. Therefore, the existing technology lacks a mathematical model for the flow of carbonate gas reservoirs in a multi-scale multi-fractured-vuggy system that utilizes seepage relations, pipe flow theory, and cavern free flow theory, and uses well testing methods to determine the physical parameters of fractures and vuggies at different scales in carbonate gas reservoirs. Summary of the Invention

[0009] To overcome the problems and shortcomings of the existing technology, this invention aims to propose a physical model of a multi-scale fracture-vuggy system based on the actual reservoir structure. There are two intersecting micro-fractures between the two karst caves, and the two karst caves are connected by large river channel fractures to form a large channel. Using the theories of seepage, pipe flow, and free flow, a mathematical model of the flow of multi-scale fracture-vuggy carbonate gas reservoirs is derived. The physical property parameters of fractures and cavities at different scales are determined by well testing.

[0010] The objective of this invention is achieved through the following technical solution:

[0011] A method for determining the physical properties of fractures and vugs at different scales in gas reservoirs includes the following steps:

[0012] The physical model construction steps are as follows: Based on the seismic data, core sampling tests, and 3D geological sculpting of the target area to describe the carbonate gas reservoir, as well as the on-site data, several carbonate gas reservoirs belonging to the "microfracture / channel large fracture / cavity" type are selected. The "microfracture / channel large fracture / cavity" type carbonate gas reservoir includes two cavities, cavities 1 and cavities 2, connected by a channel large fracture f3 and two microfractures f1 and f2. A physical model is constructed based on the fracture-cavity structure of the "microfracture / channel large fracture / cavity" type carbonate gas reservoir. The physical model includes a wellbore and two cavities, cavities 1 and cavities 2, connected by a channel large fracture f3 and two microfractures f1 and f2. One end of each of the two microfractures f1 and f2 is connected to cavities 1 and cavities 2, and the other end is connected to the bottom of the wellbore.

[0013] Specifically, in the carbonate gas reservoir of the "microfracture / channel large fracture / cavity" type, two cavities in the carbonate gas reservoir serve as the main storage space, while the channel large fracture and microfracture serve as both flow channels and secondary storage spaces. The fluid mobility outside the cavities is poor, while the fractures are coupled and connected to the cavities.

[0014] The steps for establishing the pipe flow equation are as follows: Based on fluid mechanics principles, the large crack f3 in the river channel is considered as a cylindrical pipe of constant diameter. The fluid within the model is a single-phase, non-ideal compressible gas, and the flow is an isothermal process, satisfying fluid mechanics principles. When the flow direction is the same as the horizontal direction, there is no change in elevation; therefore, there is no gravitational pressure drop. The kinetic pressure drop caused by the increase in flow velocity is ignored. The frictional pressure gradient equation is then applied. The total pressure gradient is represented by f, where f is the friction coefficient and ρ is the reservoir fluid density (unit: kg / m³). 3 Let v be the average velocity of the fluid in the large fissure in the river channel (in m / s), and D be the diameter of the large fissure f3 in the river channel (in m); establish the average velocity equation. Where R f3 The radius (in meters) of the large fissure in the river channel f3, B gLet q be the gas volume factor, q be the surface production of the gas well, and A be the cross-sectional area of ​​the large fracture in the channel. The large fracture can be considered as a complete coarse pipe, where the fluid has a large flow cross-section and high velocity, resulting in a high Reynolds number. In the Moody diagram, the friction coefficient tends to be parallel to the horizontal axis and is mainly affected by relative roughness. Therefore, the Colebrook–White formula is used to establish the friction coefficient equation. in, For relative roughness, L f3 Let ψ be the length of the large fissure in the river channel (in meters), Re be the Reynolds number, and neglect the local resistance at the connection between the large fissure and the cave, as well as the fluid flow through the micro-fissures around the connection. Assume the cave is a potential body completely filled with gas, i.e., the pressure at the fissure-cavity connection is equal to the pressure inside the cave. Then ψ f3 | x＝0 =ψ v1 | x＝0 =ψ v1 For the pressure of cave 1, The pressure in cave 2 is given by [insert pressure here], and the pressure difference between the caves is given by [insert pressure The pressure relationship between the caves is dimensionlessly transformed to establish a pressure coupling model at the connection between the large river fissure f3 and the two caves.

[0015] The coupled mathematical model establishment steps simplify the physical model constructed in the physical model construction steps into a multi-scale fracture-vuggy system planar model. Combined with the pressure coupling model established in the pipe flow equation construction steps, coupled mathematical models for seepage, free flow, and pipe flow are established for microfractures, large channel fractures, and cavernous reservoirs. Specifically, with the center of the wellbore bottom as the origin, dimensionless seepage differential equations for gas flow in microfractures f1 and f2 are established. Flow coupling equations are also established at the connections between caverns 1 and 2 and microfractures f1 and f2, as well as at the connections between microfractures f1 and f2 and the wellbore. Then, pressure connection conditions are established at the connections between caverns 1 and 2 and microfractures f1, f2, and large channel fracture f3. Finally, boundary conditions and initial conditions for the coupled mathematical model are established.

[0016] Furthermore, in the coupled mathematical model establishment step, the physical model constructed in the physical model construction step is simplified into a multi-scale fracture-cavity system planar model. Specifically, let the angles between the actual microfractures f1 and f2 and the horizontal and vertical directions be β and θ, respectively. Let the horizontal and vertical projections of the actual microfractures f1 and f2 be f1' and f2', respectively. As mentioned above, the reservoir storage space is mainly caverns, and the secondary storage space and flow channels are microfractures and large river channel fractures. The actual microfractures f1 and f2 connect cavern 1 and cavern 2, respectively. The flow of fluid in micro-fractures f1 and f2 conforms to Darcy's flow law; the large fissure f3 in the river channel connects cave 1 and cave 2, and the flow of fluid in the large fissure f3 conforms to the pipe flow law; cave 1 supplies air to micro-fracture f1, and cave 2 supplies air to micro-fracture f2, considering that cave 1 supplies air to cave 2 through the large fissure f3; the pressure and flow rate at the outlet of cave 1 and cave 2 are equal to the pressure and flow rate at the inflow of micro-fractures f1 and f2, respectively, and the pressure at the outlet of cave 1 is equal to the sum of the pressure at the inflow of the large fissure f3 and the pressure at the outlet of cave 2.

[0017] Preferably, in the coupled mathematical model establishment step, a dimensionless seepage differential equation is established for the gas flow in microfractures f1 and f2, using a coordinate system with the center of the wellbore bottom as the origin. Specifically:

[0018]

[0019] Among them, as mentioned above, It is a pseudo-pressure gradient, k * A parameter representing the ratio between the permeability and cross-sectional area of ​​two microcracks; f1D A represents the cross-sectional area of ​​the dimensionless microcrack f1; f2D The cross-sectional area of ​​the dimensionless microcrack f2; x D Represents dimensionless distance, ω j For storage-solution ratio, ψ jD For dimensionless pseudo-pressure, j = f1, f2, f3, v1, v2, w represent microcrack f1, microcrack f2, large river channel crack f3, cave 1, cave 2, and well shaft, respectively; the subscript D indicates dimensionless.

[0020] More specifically, in the step of establishing the coupled mathematical model, flow coupling equations are established at the connections between cavern 1 and cavern 2 and microcracks f1 and f2, respectively. Specifically:

[0021] The flow coupling equation at the connection between cavern 1 and microcrack f1 is as follows:

[0022]

[0023] The flow coupling equation at the connection between cavern 2 and microcrack f2 is as follows:

[0024]

[0025] Among them, L f1 L f2 V represents the actual lengths (in meters) of microfractures f1 and f2 in the reservoir. v1 V v2 This represents the volume of cave 1 and cave 2 (in meters). 3 ).

[0026] Furthermore, in the steps of establishing the coupled mathematical model, the flow coupling equations at the connection points between micro-fractures f1 and f2 and the wellbore are specifically as follows:

[0027]

[0028] Among them, C D This represents the dimensionless wellbore storage coefficient.

[0029] Furthermore, in the step of establishing the coupled mathematical model, the pressure connection conditions at the junctions of cave 1 and cave 2 with micro-cracks f1, f2, and the large river channel crack f3 are established, specifically:

[0030] The pressure connection condition at the junction of cavern 1 and microcrack f1 is as follows:

[0031] Pressure connection conditions at the junctions of micro-crack f2, large river channel crack f3, and karst caves 1 and 2

[0032]

[0033] Next, in the step of establishing the coupled mathematical model, the model boundary conditions and initial conditions are established. Specifically,

[0034] The pressure relationship between the two fractures at the inner boundary and the bottom of the well is as follows:

[0035]

[0036] Initial pressure conditions for gas reservoirs:

[0037]

[0038] The outer boundary is impermeable:

[0039]

[0040] Among them, R 1D R 2D Let t represent the dimensionless radii of cave 1 and cave 2, respectively. D It is dimensionless time.

[0041] The steps for solving the physical property parameters involve solving the coupled mathematical model established in the coupled mathematical model establishment step to obtain the bottom hole pressure solution function in Laplace space; using the obtained bottom hole pressure solution in Laplace space, the improved Stehfest numerical inversion method is used to program the bottom hole pressure solution in real space in MATLAB software, and the real space well test theoretical curve is plotted. Parameter cluster sensitivity analysis is performed on the well test theoretical curve. By analyzing the theoretical curve, the physical property parameters of the actual fractured and vulcanized reservoir are obtained. The physical property parameters include microfracture permeability, well-reservoir coefficient, vulcanization volume, fracture length, and fracture area.

[0042] Preferably, in the step of solving for the physical property parameters, the coupled mathematical model established in the step of establishing the coupled mathematical model is solved, specifically:

[0043] First, the well test mathematical model is dimensionless using the defined dimensionless quantities to obtain the dimensionless well test mathematical model.

[0044] Then, the dimensionless well test mathematical model is solved using the Laplace transform to obtain the bottomhole pressure solution function in Laplace space. This Laplace space bottomhole pressure solution function is then input into Mathematica software to obtain the bottomhole pressure solution function in Laplace space.

[0045] More specifically, the Laplace transform is first applied to the dimensionless well-testing mathematical model to obtain the Laplace space equations:

[0046] According to the foregoing description,

[0047]

[0048]

[0049]

[0050]

[0051]

[0052]

[0053]

[0054]

[0055] In the formula, For ψ f1D ψ f2D ψ v1D ψ v2D ψwD In the solution in Laplace space, s is a Laplace variable;

[0056] Then, the model is solved using the Laplace transform. Let the function f(t) be defined on [0, ∞), and f(t) be a real-valued or complex-valued function of the real variable t; then, by Laplace integral... The determined function The Laplace transform of the function f(t) is used to transform the well test mathematical model into a homogeneous system of equations in Laplace space, thereby solving for the bottom hole pressure function in Laplace space.

[0057] In the steps of solving for the physical property parameters, the specific method for obtaining the physical property parameters of the actual fractured-vuggy reservoir by performing parameter cluster sensitivity analysis on the theoretical curves from the well test, and analyzing the theoretical curves, is as follows:

[0058] Improved Stehfest numerical inversion method

[0059]

[0060] The bottom hole pressure solution ψ in real space was obtained by using the improved Stehfest numerical inversion method. wD (t D The relationship between N and the bottom hole pressure solution function in Laplace space, where N is an even number and its value ranges from 16 to 30.

[0061] Furthermore, the bottom hole pressure solution in real space was obtained by programming in MATLAB software, and typical well test curves of multi-scale fractured-vuggy reservoirs were plotted.

[0062] The above describes the sensitivity analysis of key parameter clusters in the well test model. Specifically, it involves changing a key parameter in the typical well test curve to obtain the typical curve shape of the parameter under different values, and summarizing the variation law of fluid flow in the fracture.

[0063] By adjusting parameters such as fracture geometry, cavern radius, permeability of two microfracture systems, and the ratio of fracture cross-sectional area, the actual curve is fitted to estimate reservoir parameter values. Based on this, the reservoir parameter values ​​are further adjusted to fit the theoretical pressure and pressure derivative curves to obtain fracture-cavity reservoir parameters.

[0064] Beneficial effects:

[0065] Compared with existing technical solutions, the beneficial effects of the technical solution provided by this invention are as follows:

[0066] (1) This invention proposes a method for determining the physical properties of fractures and vugs at different scales in gas reservoirs, providing a supporting well test interpretation method for obtaining reservoir parameters of fractured-vug carbonate gas reservoirs and understanding the distribution of large-scale caverns and fractures in fracture-vug models. The method established in this invention mainly involves a well test mathematical model corresponding to a fracture-vug physical model. It considers the distribution of fractures and vugs and their connection methods based on actual geological data. Although current well test mathematical models are constantly being updated in terms of mathematical and physical methods, there are few well test mathematical models that combine multiple flow theories, resulting in low utilization of well test data and limited well test information mining for fractured-vug carbonate gas reservoirs.

[0067] (2) The fracture-vuggy closed-loop connection mode in this invention, combined with the situation of discontinuous medium reservoirs where microfractures, large channel fractures, and karst caves coexist, improves the understanding of fracture-vuggy carbonate reservoirs and takes into account the differences in physical properties of large-scale karst caves, large fractures, and microfractures. It can explain parameters such as karst cave volume, large fracture length, micro fracture length, micro fracture cross-sectional area, and reservoir permeability in the fracture-vuggy closed-loop connection mode of the reservoir, and obtain more comprehensive reservoir parameters and fracture-vuggy structure parameters, providing technical support for the formulation of oilfield development plans.

[0068] (3) The mathematical and physical methods for establishing the well test mathematical model of the fractured-vuggy closed-loop connection mode discontinuous medium reservoir in this invention are simple and easy to implement. It provides the bottom hole pressure solution in Laplace space, which is convenient to solve and has a fast calculation speed. The discontinuous medium reservoir with microfractures, channel fractures, and karst caves coexisting in the fractured-vuggy closed-loop connection mode provided by this invention can help technicians fully understand the dynamics of fractured-vuggy gas reservoirs, improve the utilization rate of well test data, and provide a more practical well test interpretation model and method for understanding the distribution and combination of karst caves and fractures of different scales in fractured-vuggy oil reservoirs.

[0069] (4) This invention can take into account large and micro fractures of different lengths, different seepage cross-sectional areas and different flow capacities; it can also take into account large-scale karst caves of different volumes and different storage capacities; it can also take into account the situation of non-continuous medium carbonate rock reservoirs with micro fractures, large river channel fractures and karst caves with different permeability parameters, storage capacity and relative permeability.

[0070] (5) The method of determining the physical properties of fractures and vulcanizations at different scales in gas reservoirs according to this invention includes applying the well test mathematical model to the well test analysis and interpretation technology of discontinuous medium carbonate reservoirs with microfractures, large channel fractures, and karst caves. This solves the well test interpretation problem of fracture-vulcanization closed-loop connection patterns in discontinuous medium carbonate reservoirs with microfractures, large channel fractures, and karst caves. By solving for formation parameters, it accurately evaluates and effectively develops fracture-vulcanization gas reservoirs, and provides a deeper understanding of the complex fracture-vulcanization structure in fracture-vulcanization carbonate reservoirs.

[0071] (6) The present invention provides a method for determining the physical properties of fractures and vulcanizations at different scales in gas reservoirs. The physical model of these fractures and vulcanizations more closely approximates the actual discontinuous medium fractured-vulcanized reservoir structure where microfractures, large channel fractures, and large karst caves coexist. The well test mathematical model corresponding to this physical model incorporates different flow theory methods, comprehensively considering three different flow modes in the reservoir: microfracture seepage, large channel fracture pipe flow, and karst cave free flow. It successfully couples the three different scales of media together to establish relevant mathematical expressions. This overcomes the shortcomings of existing well test technologies for fractured-vulcanized gas reservoirs, solves the well test interpretation problem for reservoirs with this type of closed-loop fractured-vulcanization connection pattern, and obtains the bottom hole pressure solution in the real space of the reservoir structure by solving the well test mathematical model of the closed-loop fractured-vulcanization connection pattern. Then, typical well test curves are plotted, formation parameters are obtained, and a well test interpretation method for the closed-loop fractured-vulcanization connection pattern reservoir is determined. This allows for accurate evaluation and effective development of fractured-vulcanized oil reservoirs, and a deeper understanding of the complex fractured-vulcanization structure in fractured-vulcanized reservoirs. Attached Figure Description

[0072] The foregoing and hereinafter detailed description of the invention becomes clearer when read in conjunction with the following drawings, in which:

[0073] Figure 1 A top view of the model of the slotted structure;

[0074] Figure 2 A frontal view of the model of the slotted hole structure;

[0075] Figure 3 A schematic diagram of the flow in the f3 fissure of the large river channel;

[0076] Figure 4 A simplified schematic diagram of a multi-scale slotted system model;

[0077] Figure 5 Typical curves of large-scale fractured-vuggy carbonate gas reservoirs;

[0078] Figure 6 The effect of the volume of cavern 1 on the typical curve;

[0079] Figure 7 The effect of the volume of cave 2 on the typical curve;

[0080] Figure 8 The effect of the cross-sectional area of ​​crack 1 on the typical curve;

[0081] Figure 9 To investigate the effect of changing the cross-sectional area of ​​crack 2 on the typical curve. Detailed Implementation

[0082] The following specific embodiments further illustrate the technical solutions for achieving the objectives of this invention. It should be noted that the technical solutions protected by this invention include, but are not limited to, the following embodiments.

[0083] This embodiment provides a method for determining the physical properties of fractures and caverns at different scales in gas reservoirs. Based on the actual "microfracture / channel large fracture / cavity" type carbonate gas reservoir reservoir structure, a new multi-scale fracture-cavity system physical model is established. This model includes a wellbore and two cavities, cavities 1 and cavities 2, connected by a channel large fracture f3 and two microfractures f1 and f2. One end of each microfracture f1 and f2 is connected to cavities 1 and cavities 2, respectively, and the other end is connected to the bottom of the wellbore. In this multi-scale fracture-cavity system physical model, there are two microfractures that are interlaced between the two cavities, and the two cavities are connected through the channel large fracture to form a large channel. Then, a well test mathematical model is established for the corresponding fracture-cavity closed-loop connection mode reservoir. The mathematical model is solved, and finally, theoretical curves are obtained. The interpretation parameters can be obtained by analyzing the theoretical curves.

[0084] Specifically, in the physical model, there are two intersecting micro-cracks connecting the two caves. The well shaft is located between the two caves and the two caves are connected by a large crack in the river channel, forming a large channel in the shape of a gourd. The entire system of well shaft, crack, and cave is a closed loop connection.

[0085] Based on the pipe flow theory, the large river channel crack in the physical model of the fracture-cavity structure is extracted and simplified into a cylindrical pipe model. Caves 1 and 2 are filled, and the caves are always regarded as equipotential bodies (the pressure inside the cave is equal everywhere). Cracks f1 and f2 simultaneously supply air to the wellbore. The flow of fluid in micro-cracks f1 and f2 satisfies Darcy's law. Cave 1 supplies air to crack f1, and cave 2 supplies air to crack f2. Considering that cave 1 supplies air to cave 2 through crack f3, the fluid obeys the law of conservation of mass at the interface between the cave and the crack.

[0086] A mathematical model describing the physical characteristics of fractures and vulcanizations in reservoirs is established. The model is solved, and the real-space solution is obtained through programming in MATLAB. The theoretical curves are plotted, and the relevant fracture and vulcanization physical parameters can be obtained by analyzing the theoretical curves. The specific process is as follows:

[0087] (1) Establish the flow equations for the cylindrical pipe model:

[0088] Based on the descriptions of this type of carbonate gas reservoir using seismic data, core sampling, and 3D geological sculpting of the study area, and with the aid of field data, the reservoir type is identified as "microfracture / channel fracture / cavitation". Cavities are the primary reservoir space, while channel fractures and microfractures serve as both flow channels and secondary reservoir spaces. The external fluid mobility of the cavities is poor, and fractures are coupled with the cavities. Based on this understanding of the reservoir, it can be simplified as follows: Figure 1The schematic diagram of the slotted structure model shown (the slotted system is on the same horizontal plane) or Figure 2 The schematic diagram of the slotted structure model shown (the slotted system is on the same vertical plane) is not limited to this type of slotted structure model. Figure 1 and Figure 2 This means that the crack can connect to the cave at any angle.

[0089] Furthermore, the large fissure in the river channel is extracted separately and simplified into a cylindrical pipe model, such as... Figure 3 As shown, the flow equation for pipe flow is established, and the process is as follows:

[0090] The large fissure in the river channel is treated as a cylindrical pipe of uniform diameter. The fluid within the model is a single-phase, non-ideal compressible gas, and the flow is an isothermal process, satisfying the principles of fluid mechanics. That is, when the flow direction is the same as the horizontal direction, there is no change in elevation, therefore, there is no gravitational pressure drop, and the kinetic pressure drop caused by the increase in flow velocity is ignored. Therefore, the total pressure gradient is the frictional pressure gradient.

[0091] The average flow velocity equation in the above frictional pressure gradient equation is: Substituting the average velocity equation into the friction pressure gradient equation, we can obtain...

[0092] In establishing the above pipe flow equations, the Colebrook-White formula is needed to establish the friction coefficient equation. A large crack can be considered a complete, thick pipe, where the fluid has a large cross-sectional area and high velocity, resulting in a large Reynolds number. In the Moody diagram, the friction coefficient tends to be parallel to the horizontal axis and is mainly affected by relative roughness. Therefore, the friction coefficient formula is:

[0093]

[0094] The pressure gradient equation is separated using the method of variable integration:

[0095]

[0096] In establishing the above-mentioned pipe flow equation, it is necessary to establish the pressure coupling equation at the connection between the large river channel fissure f3 and karst caves 1 and 2. Specifically, the local resistance at the connection between the large fissure and the karst caves and the flow channeling of fluid in the micro-fissures around the connection are ignored. Furthermore, it is assumed below that the karst caves are potential bodies completely filled with gas, that is, the pressure at the connection between the fissure and the karst caves is equal to the pressure inside the karst caves.

[0097] ψ f3 | x＝0 =ψ v1 | x＝0 =ψ v1

[0098]

[0099] The pressure coupling relationship between caves 1 and 2 is established as follows:

[0100]

[0101] The pressure relationship between caves 1 and 2 is dimensionlessly transformed as follows:

[0102]

[0103] (2) Establish the dimensionless differential equation of gas flow in the two micro-cracks f1 and f2 using a coordinate system with the center of the bottom of the well as the origin.

[0104] (3) Establish flow coupling equations at the junctions of caves, fissures, and well shafts;

[0105] (4) Establish pressure connection conditions at the junction of the crack and the cave;

[0106] (5) Establish the model boundary conditions and initial conditions;

[0107] The above (2)-(5) simplifies the physical model of fractured-vuggy gas reservoirs into two interconnected microfractures between two karst caves. The wellbore is located between the two caves, and the two caves are connected by a large channel through a river channel fracture, forming a large channel, resembling a gourd. The entire system of wellbore, fractures, and caves is a closed loop connection, such as... Figure 4 The diagram shown is a simplified schematic of a multi-scale slotted hole system model.

[0108] Specifically, the first step is to establish the dimensionless differential equations for gas flow in the two cracks f1 and f2. The differential equation for gas flow in crack f1 is as follows:

[0109] 1) The dimensionless differential equation for gas flow in crack f1:

[0110]

[0111] 2) The dimensionless differential equation for gas flow in crack f2:

[0112]

[0113] Then, the flow coupling equations at the connection points of the caves, cracks, and wells are established by constraining the connection conditions, boundary conditions, and initial conditions of the model between the cracks, caves, and wells.

[0114] At the junction of the fissure and the cave, the two flow modes are coupled by applying equal pressure and flow rate conditions:

[0115] 1) Flow coupling equation at the connection between cavern 1 and fissure f1:

[0116]

[0117] 2) Flow coupling equation at the connection between cavern 2 and fissure f2:

[0118]

[0119] 3) Flow coupling equations at the connection points between fractures f1 and f2 and the wellbore:

[0120]

[0121] 4) Pressure connection conditions at the junction of cavern 1 and fissure f1:

[0122]

[0123] 5) Pressure connection conditions at the junctions of cracks f2 and f3 with caves 1 and 2:

[0124]

[0125] 6) The pressure relationship between the two fractures at the inner boundary and the bottom of the well is:

[0126]

[0127] 7) Initial pressure conditions of the gas reservoir:

[0128]

[0129] 8) Impermeable conditions at the outer boundary:

[0130]

[0131] (6) Based on the established well test mathematical model, solve for and obtain the real-space bottom hole pressure solution, specifically:

[0132] Step 1: Solve the dimensionless well test model using the Laplace transform to obtain the Laplace space bottom hole pressure solution;

[0133] Step 2: Using Stehfest numerical inversion, the bottom-hole pressure solution in Lagrange space is inverted to real space to obtain the bottom-hole pressure solution in real space.

[0134] Furthermore, in step 2 above, the model is solved using the Laplace transform. Let the function f(t) be defined on [0, ∞), and f(t) be a real-valued or complex-valued function of the real variable t; then, by the Laplace integral... The determined function The integral transformation of the function f(t) is called the Laplace transform. Using this integral transform, the established well test model can be transformed into a homogeneous system of equations in Laplace space. The system of equations is then input into Mathematica software to solve for the bottom-hole pressure function in Laplace space, thus yielding the bottom-hole pressure function in Laplace space.

[0135]

[0136] Where a=ω f1 A f1D b = ω f2 A f2D ; g = C D ;

[0137] Step 3, Solve the bottom-hole pressure ψ in real space wD (t D The relationship between the solution function of the bottom hole pressure in the Laplace space of step 2 above and the above-mentioned step 2 is obtained by the following improved Stehfest numerical inversion technique:

[0138]

[0139] Where N is an even number, and its value ranges from 16 to 30.

[0140] (7) Using the obtained bottom hole pressure solution in the real space, draw the theoretical curve of the real space well test, and fit the theoretical pressure data with the measured pressure recovery data to obtain the fitting results. The physical property parameters of the actual reservoir with fractures and caverns are obtained. The physical property parameters include microfracture permeability, well-reservoir coefficient, cavern volume, fracture length, and fracture area.

[0141] Furthermore, by programming in MATLAB software, the bottom hole pressure solution in real space was obtained, and typical well test curves for multi-scale fractured-vuggy reservoirs were plotted, such as... Figure 4 As shown.

[0142] Using the obtained bottom-hole pressure solution in the real space, the theoretical curve of the real space well test is plotted. The theoretical pressure data is then fitted with the measured pressure recovery data to obtain the fitting results. The physical properties of the actual fractured reservoir are then obtained, including microfracture permeability, well-reservoir coefficient, cavity volume, fracture length, and fracture area.

[0143] In the same log-log coordinate system, log-log curves of pressure and pressure derivative of the measured wells are plotted using pressure recovery data from actual wells. Using basic parameter data, by continuously adjusting reservoir parameters and fitting parameters, and repeatedly debugging the N value in the numerical inversion program, a high degree of fit is achieved between the theoretical log-log curve of the bottom-hole pressure solution in real space and the log-log curve of the measured wells, thus obtaining the interpretation results data.

[0144] For example:

[0145] Table 1. Basic Parameter Data of Example Wells

[0146] 5.48 (well logging) 0.10795(naked eye) 5 dry air

[0147] Table 2 Physical property parameters of fractures and cavities at different scales in gas reservoirs.

[0148]

[0149]

[0150] Based on the above scheme, the gas parameters of the gas reservoir are calculated in the following way to obtain the well test interpretation results data:

[0151] Pressure fitting value:

[0152] Time-fitted values:

[0153] Well-reservoir accumulation coefficient: C = C D (φ f1 C f1 +φ f2 C f2 +φ v1 C v1 +φ v2 C v2 )

[0154] Storage capacity ratio:

[0155] Crack length: L j =L jD r w (j=f1,f2,f3)

[0156] Cross-sectional areas of cracks f1 and f2:

[0157] Crack f3 cross-sectional radius: R f3 =R f3D r w

[0158] Volume of Cave 1:

[0159] Volume of Cave 2:

[0160] This parameter represents the ratio between the permeability and cross-sectional area of ​​two fracture systems.

[0161]

[0162] The larger the volume of the distal well cavern 1, the longer the time required for pressure wave propagation and the greater the gas supply capacity to the fracture. The depth and width of the trough also increase accordingly; that is, the second cavern's response characteristic segment becomes wider and deeper. Furthermore, the larger the volume of distal well cavern 1, the longer the energy depletion period will be, delaying the time to reach a pseudo-stable gas supply state. This figure also illustrates that when two caverns are connected in parallel, changing the size of one cavern does not affect the response characteristic segment of the other cavern on the curve. In other words, when the pressure wave propagates in the gas layer connected to the fracture-cavity joint, no strong pressure disturbance is formed, and the gas supply capacity of each cavern to the fracture does not change significantly. Figure 6 As shown.

[0163] The larger the volume of near-wellbore cavity 2, the faster its gas supply rate will exceed that of far-wellbore cavity 1, resulting in a wider and deeper first depression. The gas flow velocity in the near-wellbore fracture is also relatively higher than that in the far-wellbore fracture, leading to a more pronounced flow characteristic in the near-wellbore fracture and a weakened flow characteristic in the far-wellbore fracture. This is reflected in the curve as a shorter linear flow section in the far-wellbore fracture, such as... Figure 7 As shown.

[0164] The larger the cross-sectional area, the faster the energy loss in the far-well cavity 1, and the more rapidly its cavity space is compressed, shortening the propagation path of the pressure wave and resulting in a weakening of the concave response segment of the far-well cavity 1. Simultaneously, the increased cross-sectional area of ​​the far-well fracture 1 amplifies the linear flow of the fracture, manifesting as a greater separation between the pressure curve and the pressure conduction curve, such as... Figure 8 As shown.

[0165] The mechanism of the cross-sectional area of ​​the far-wellbore fracture 1 is similar to that of the near-wellbore fracture 2, but the difference is that when the energy in the near-wellbore cavern 1 is rapidly depleted, the linear flow characteristics of the far-wellbore fracture 1 will be more pronounced. As the main gas supply section, the time for the far-wellbore cavern 1 to continuously supply gas to the fracture is correspondingly shortened, which is reflected in the curve as the second concave section narrowing, as shown in the curve. Figure 9 As shown.

[0166] The method of determining the physical properties of fractures and cavities of different scales in gas reservoirs in this invention fully considers the existence of large-scale karst caves, large-scale fractures and microfractures in the reservoir, and combines three different flow modes for coupled processing, which has important practical application significance.

[0167] It should be noted first that the algebraic expressions of the relevant measurement parameters involved in this scheme are quite complex. To avoid ambiguity, the algebraic expressions used will be explained here. Among them, the basic reference physical property parameters include the main gas reservoir parameters of the fracture-vuggy system:

[0168] k f1 k f2ψ represents the permeability (in mD) of the fractured system f1 and f2; i Original simulated pressure of gas reservoir (unit: MPa) 2 / mP·s); ψ j This indicates the pseudo-pressure of the gas (unit: MPa). 2 / mPa·s), where j=f1, f2, f3, v1, v2, w represent fracture f1, fracture f2, fracture f3, cavern 1, cavern 2, and well bottom, respectively; q represents the surface production of the gas well (calculated under conditions of P=0.101MPa, T=293.15K, unit of measurement 10 4 m 3 / d); T represents the temperature of the gas reservoir (in K); μ gi Indicates the original viscosity of the gas (in mPa·s); C j φ represents the compressibility of a gas (unit: 1 / MPa); j Indicates porosity; L f1 L f2 L f3 The value of f1 represents the actual length of fractures f1, f2, and f3 in the reservoir (in meters); x represents the horizontal distance on the number axis (in meters); r w Indicates the radius of the wellbore (in meters); A f1 A f2 This represents the cross-sectional area of ​​cracks f1 and f2 (in meters). 2 );V v1 V v2 This represents the volume of caves 1 and 2 (in meters). 3 ); t represents time (in hours); C represents the wellbore storage coefficient (in MPa / m³). 3 ); R v1 R v2 ρ represents the radii (in meters) of caves 1 and 2, respectively; g Air density (unit: kg / m³) 3 ).

[0169] The key physical properties associated with the large fissure pipe flow model in river channels include: The pseudo-pressure gradient is given by f; the friction coefficient is given by ρ; and the reservoir fluid density is given by ρ (in kg / m³). 3 v is the average flow velocity of the fluid in the large fracture, in m / s; D is the diameter of the large fracture f3 (in m); R f3 B is the radius of the large crack f3 (in meters); g This is the gas volume coefficient; For relative roughness; L f3 is the length of the large crack (in meters); Re is the Reynolds number.

[0170] The subscript D indicates dimensionless, where some physical property parameters are defined as dimensionless as: k * ψ represents the ratio of permeability to fracture cross-sectional area between two fracture systems; jD Dimensionless pressure; L f1D L f2D L f3D These represent the dimensionless actual lengths of fractures f1, f2, and f3 in the reservoir, respectively; x f1D x f2D Let x represent the dimensionless lengths of the projections of cracks f1 and f2 in the horizontal or vertical directions, respectively; D A represents dimensionless distance; f1D V represents the cross-sectional area of ​​the dimensionless crack f1; v1D A represents the volume of a dimensionless cavern. f2D The cross-sectional area of ​​the dimensionless crack f2; V v2D t represents the volume of a dimensionless cavern. D Dimensionless time; C D ω represents the dimensionless wellbore storage coefficient; j Storage-solution ratio; R v1D R v2D R f3D Let ρ represent the dimensionless radii of cave 1, cave 2, and large fissure f3, respectively; D This indicates the relative density of a gas.

[0171] The aforementioned dimensionless variables include:

[0172]

[0173]

[0174]

[0175]

[0176]

[0177]

[0178]

[0179]

[0180]

[0181]

[0182]

[0183]

[0184]

Claims

1. A method for determining the physical properties of fractures and vugs at different scales in gas reservoirs, characterized in that, Includes the following steps: The physical model construction steps involve selecting several carbonate gas reservoirs belonging to the "microfracture / channel fracture / cavitation" type based on seismic data, core sampling tests, and 3D geological sculpting of the target area, as well as on-site data. These "microfracture / channel fracture / cavitation" type carbonate gas reservoirs include two reservoirs connected by a single channel fracture. f 3 and two microcracks f 1. f A physical model is constructed based on the fracture-cavity structure of a carbonate gas reservoir, consisting of two connected caverns 1 and 2, which are described as "microfracture / large channel fracture / cavity". The physical model includes a wellbore and two caverns connected by a large channel fracture. f 3 and two microcracks f 1. f Two connected caves, Cave 1 and Cave 2, with two micro-cracks. f 1. f One end of 2 is connected to cave 1 and cave 2 respectively, and the other end is connected to the bottom of the well shaft; Steps for establishing pipe flow equations, including large cracks in the river channel. f 3 is considered as a cylindrical pipe of uniform diameter, and the fluid inside the model is a single-phase non-ideal compressible gas. The kinetic energy pressure drop caused by the increase in flow velocity is ignored, and the friction pressure gradient equation is applied. As the total pressure gradient, where f The coefficient of friction, The density of the reservoir fluid is expressed in kg / m³. 3 , v The average flow velocity of the fluid in the large fissure of the river channel, in m / s. D Large cracks in the river channel f 3. Diameter, unit: meters; establish the average flow velocity equation. ,in R f3 Large cracks in the river channel f 3. Radius, in meters. Bg Let q be the gas volume coefficient, q be the surface production rate of the gas well, and A be the cross-sectional area of ​​the large fracture in the river channel; the friction coefficient equation is established using the Colebrook–White formula. ;in, For relative roughness, L f3 The length of the large crack in the river channel, in meters. Re Let be the Reynolds number; and neglecting the local resistance at the junction of the large fissure and the cavern, as well as the fluid flow through the micro-fissures around the junction, assume the cavern is a potential body completely filled with gas, i.e., the pressure at the fissure-cavity junction is equal to the pressure inside the cavern. For the pressure of cave 1, The pressure in cave 2 is given by [insert pressure here], and the pressure difference between the caves is given by [insert pressure The pressure relationship between the karst caves was dimensionlessly transformed to establish the large river channel fissure. f3 Pressure coupling model at the connection between the two caverns ; The coupled mathematical model establishment steps simplify the physical model built in the physical model construction steps into a multi-scale fractured-vuggy system planar model. Combined with the pressure coupling model established in the pipe flow equation establishment steps, coupled mathematical models of seepage, free flow, and pipe flow are established for microfractures, large river channel fractures, and cavernous reservoirs. Specifically, a coordinate system with the center of the wellbore bottom as the origin is used to establish the gas flow in microfractures. f 1. Microcracks f The dimensionless differential equations of seepage flow in section 2 are used to establish the relationships between cavern 1 and cavern 2 and microcracks, respectively. f 1 and microcracks f 2. Flow coupling equations at the connection and microcracks f 1 and microcracks f 2. The flow coupling equation at the connection with the wellbore is then established; then, the flow coupling equations for cavern 1 and cavern 2 with the microfractures are established. f 1. Microcracks f 2 and large cracks in the river channel f 3. Pressure connection conditions at the connection point; finally, establish the boundary conditions and initial conditions of the coupled mathematical model; The physical model constructed in the physical model building step is simplified into a multi-scale crack-cavity system planar model. Specifically, this means assuming the actual microcracks... f 1. f The angles between 2 and the horizontal and vertical directions are respectively β, θ Actual microcracks f 1. f 2. Horizontal and vertical projections are f 1', f 2', Actual microcracks f 1. f 2 connects cave 1 and cave 2 respectively, and the fluid flows through the micro-cracks. f 1. f The flow in section 2 conforms to Darcy's seepage law; large cracks in the river channel. f 3. Connecting Cave 1 and Cave 2, fluid flows through a large fissure in the river channel. f The flow in the third type conforms to the pipe flow law; the karst cave has micro-fractures in direction. f 1. Gas supply, 2. Micro-cracks in the cave f 2. Gas supply, considering cave 1 through a large fissure in the river channel. f 3. Gas is supplied to cave 2; the pressure and flow rate at the outlets of caves 1 and 2 are respectively equal to those at the micro-fractures. f 1. f 2. Pressure and flow rate at the inflow point; the pressure at the outflow point of cave 1 is equal to that of the major fissure in the river channel. f 3. The sum of the pressure at the inflow point and the pressure at the outflow point of cave 2; The steps for solving the physical property parameters involve solving the coupled mathematical model established in the coupled mathematical model establishment step. First, the well test mathematical model is dimensionless using defined dimensionless quantities to obtain a dimensionless well test mathematical model. Then, the dimensionless well test mathematical model is solved using the Laplace transform to obtain the Laplace space bottom hole pressure solution function. The Laplace space bottom hole pressure solution function is then input into Mathematica software to obtain the bottom hole pressure solution function in Laplace space. Using the obtained bottom hole pressure solution in Lagrange space, the improved Stehfest numerical inversion method was programmed in MATLAB software to obtain the bottom hole pressure solution in real space and plot the real space well test theoretical curve. Parameter cluster sensitivity analysis was performed on the well test theoretical curve. By analyzing the theoretical curve, the physical property parameters of the actual fractured and vulcanized reservoir were obtained. The physical property parameters include microfracture permeability, well-reservoir coefficient, vulcanization volume, fracture length, and fracture area.

2. The method for determining the physical properties of fractures and vugs at different scales in gas reservoirs as described in claim 1, characterized in that, In the coupled mathematical model establishment step, a coordinate system with the center of the wellbore bottom as the origin is established to model the gas flow in the microfractures. f 1. Microcracks f The dimensionless seepage differential equation for the flow in section 2 is as follows: ， in, It is a pseudo-pressure gradient. k * This parameter represents the ratio between the permeability and cross-sectional area of ​​two microcracks. A f1D Indicates a dimensionless crack f 1. Cross-sectional area; A f2D Indicates a dimensionless crack f 2. Cross-sectional area; x D Indicates dimensionless distance, For storage-solution ratio, For dimensionless pseudo-pressure, j= f 1. f 2. f 3. v1, v2, and w represent microcracks, respectively. f1 Microcracks f2 Large cracks in the river channel f3 Cave 1, Cave 2, Well; Subscript D indicates dimensionless.

3. The method for determining the physical properties of fractures and vugs at different scales in gas reservoirs as described in claim 2, characterized in that, In the steps of establishing the coupled mathematical model, cave 1 and cave 2 are respectively established with microcracks. f1 and microcracks f2 The flow coupling equation at the connection point, specifically, for cavern 1 and the fissure. f1 Flow coupling equation at the connection: Cave 2 and Cracks f 2. Flow coupling equation at the connection point: in, Lf 1. Lf 2 indicates a microcrack f1 Microcracks f2 The actual length within the reservoir, measured in meters (m). Vv 1. Vv 2 represents the volume of cave 1 and cave 2, in meters (m³). 3 .

4. The method for determining the physical properties of fractures and vugs at different scales in gas reservoirs as described in claim 3, characterized in that, In the process of establishing the coupled mathematical model, microcracks f1 and microcracks f2 The flow coupling equation at the connection with the wellbore is as follows: ， in, CD This represents the dimensionless wellbore storage coefficient.

5. The method for determining the physical properties of fractures and vugs at different scales in gas reservoirs as described in claim 4, characterized in that, In the steps of establishing the coupled mathematical model, cave 1 and cave 2 are established in relation to microcracks. f 1. Microcracks f 2 and large cracks in the river channel f 3. Pressure connection conditions at the connection point, specifically: Cave 1 and micro-cracks f The pressure connection conditions at the connection point are as follows: microcracks f2 Large cracks in the river channel f3 Pressure connection conditions at the connection points with cave 1 and cave 2 .

6. The method for determining the physical properties of fractures and vugs at different scales in gas reservoirs as described in claim 5, characterized in that, In the steps of establishing the coupled mathematical model, the model boundary conditions and initial conditions are established, specifically: The pressure relationship between the two fractures at the inner boundary and the bottom of the well is as follows: ； Initial pressure conditions for gas reservoirs: ； The outer boundary is impermeable: ； in, R 1 D , R 2 D Let these represent the dimensionless radii of cave 1 and cave 2, respectively. t D It is dimensionless time.

7. The method for determining the physical properties of fractures and vugs at different scales in gas reservoirs as described in claim 1, characterized in that, More specifically, the Laplace transform is first applied to the dimensionless well-testing mathematical model to obtain the Laplace space equations: ,in , , , , , , , In the formula, for The solution in Laplace space, s For Laplace variables; Then, the Laplace transform is used to solve the model. Let the function be... f(t) It is defined on [0,∞). f(t) It is a real-valued or complex-valued function of the real variable t; obtained by the Laplace integral. The determined function Called a function f (t) The Laplace transform, specifically the Laplace integral transform, can be used to transform the well test mathematical model into a homogeneous system of equations in Laplace space, thereby solving for the bottomhole pressure function in Laplace space. .

8. The method for determining the physical properties of fractures and vugs at different scales in gas reservoirs as described in claim 1, characterized in that, In the steps of solving for the physical property parameters, the specific method for obtaining the physical property parameters of the actual fractured-vuggy reservoir by performing parameter cluster sensitivity analysis on the theoretical curves from the well test, and analyzing the theoretical curves, is as follows: Improved Stehfest numerical inversion method ， The bottom-hole pressure solution in real space was obtained by using the improved Stehfest numerical inversion method. The relationship between the bottom hole pressure solution function in Laplace space and N, where N is an even number and its value ranges from 16 to 30.

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