Method for determining low-permeability tight reservoir single-well CO2 gas flooding and injecting speed and related device

Abstract

The invention belongs to the field of single-well gas injection, and discloses a low-permeability tight oil reservoir single-well CO2 gas injection and displacement speed determination method and a related device. The method comprises the following steps: constructing a carbon dioxide gas flooding and injection velocity model containing matrix overburden pressure permeability and starting pressure gradient; the method comprises the following steps: testing the permeability of a reservoir core sample of a tight sandstone reservoir under different effective stresses to obtain a first relation curve, and carrying out regression analysis to obtain a first coefficient corresponding to the matrix overburden pressure permeability; respectively carrying out starting pressure gradient testing on the core samples with different matrix overburden pressure permeability to obtain a second relation curve, and carrying out regression analysis to obtain a second coefficient corresponding to the starting pressure gradient; and the collected basic data, the first coefficient and the second coefficient are input into the carbon dioxide flooding gas injection speed model for calculation, and the gas injection speed of the single well is obtained. According to the method, the carbon dioxide flooding and gas injection speed can be better optimized, and therefore the exploitation efficiency of an oil field is improved.

Description

Technical Field

[0001] This application belongs to the field of single-well gas injection, and particularly relates to a method for determining the gas injection rate of single-well CO2 flooding in low-permeability tight oil reservoirs and related devices. Background Art

[0002] The CCUS technology has currently become the focus of carbon reduction in the energy industry; among them, the CCUS-EOR technology can not only drive oil but also reduce carbon, and has broad application prospects especially in unconventional oil reservoirs such as tight oil and shale oil.

[0003] In the CCUS-EOR technology, the design of the carbon dioxide injection rate is crucial, which directly affects the development effect of carbon dioxide flooding. However, the current injection rate design mainly relies on reservoir numerical simulation and experience reference, often only recommending a so-called "optimal" injection rate, while ignoring the influence of reservoir physical properties, thickness and other heterogeneities. This "one-size-fits-all" design method is particularly inapplicable in tight sandstone oil reservoirs because the influence of the starting pressure gradient on the formation gas absorption capacity cannot be underestimated. Summary of the Invention

[0004] The purpose of this application is to overcome the defects in the prior art and provide a method for determining the gas injection rate of single-well CO2 flooding in low-permeability tight oil reservoirs and related devices.

[0005] This application provides a method for determining the gas injection rate of single-well CO2 flooding in low-permeability tight oil reservoirs, including:

[0006] Constructing a carbon dioxide injection rate model including matrix overburden permeability and starting pressure gradient;

[0007] Testing the permeability of reservoir core samples of tight sandstone reservoirs under different effective stresses to obtain a first relationship curve between the matrix overburden permeability and the effective stress;

[0008] Performing regression analysis on the first relationship curve to obtain a first coefficient corresponding to the matrix overburden permeability;

[0009] Respectively performing starting pressure gradient tests on the core samples with different matrix overburden permeabilities to obtain a second relationship curve between the starting pressure gradient and the matrix overburden permeability;

[0010] Performing regression analysis on the second relationship curve to obtain a second coefficient corresponding to the starting pressure gradient;

[0011] Collecting basic data to be input into the carbon dioxide injection rate model;

[0012] Inputting the basic data, the first coefficient and the second coefficient into the carbon dioxide injection rate model for calculation to obtain the gas injection rate of a single well.

[0013] Optionally, the carbon dioxide flooding gas injection rate model has the following expression:

[0014]

[0015] where q i is the carbon dioxide injection rate of a single well, K o is the measured permeability value of the core of the reservoir rock in the ground test, a and b are the first coefficients, c and d are the second coefficients, P h is the overlying rock pressure of the reservoir at the reservoir depth, P f is the formation pressure of a single well test, K rg is the relative permeability of carbon dioxide at the residual oil saturation, P i is the bottom hole pressure of a single well for gas injection, P f is the formation pressure of a single well test, A is the area of the injection-production well group, r w is the wellbore diameter, ρ g is the average density of carbon dioxide under formation conditions, h i is the effective thickness of the single well reservoir, B g is the volume coefficient of carbon dioxide, μ g is the viscosity of carbon dioxide under formation conditions.

[0016] Optionally, startup pressure gradient tests are respectively carried out on the core samples with different matrix overburden permeabilities, including:

[0017] Dry the core samples and put them into a physical simulation device for vacuum treatment;

[0018] Heat the physical simulation device to the temperature of the test reservoir and inject carbon dioxide into the physical simulation device at a constant pressure;

[0019] Change the injection pressure when the flow rate is stable;

[0020] Based on multiple pressure gradients, obtain the seepage velocities corresponding to different pressure gradients;

[0021] According to the multiple pressure gradients and the seepage velocities, plot the third relationship curve of the pressure gradient and the seepage velocity;

[0022] Project in a two-dimensional coordinate system, fit the third relationship curve, and obtain the fluid pressure gradient corresponding to the zero outlet seepage velocity as the startup pressure gradient of the core sample.

[0023] Optionally, based on multiple pressure gradients, obtain the seepage velocities corresponding to different pressure gradients, including:

[0024] The increase value of each pressure gradient is 5%-10% of the end pressure.

[0025] Optionally, the basic data includes:

[0026] The thickness, matrix permeability, oil reservoir burial depth, well spacing and row spacing of injection and production wells of different single wells;

[0027] The wellhead pressure of different gas injection wells and the average formation pressure of different gas injection well groups;

[0028] The density and viscosity of carbon dioxide under reservoir conditions;

[0029] The carbon dioxide volume coefficient and the relative permeability of carbon dioxide at residual oil saturation.

[0030] Optionally, the expression of the first relationship curve:

[0031]

[0032] where K σ is the confining pressure permeability, K o is the gas logging permeability value of the reservoir core tested on the ground, and a and b are the first coefficients, P f is the formation pressure tested for a single well, and P h is the overlying rock pressure of the reservoir at the reservoir depth.

[0033] Optionally, the expression of the second relationship curve:

[0034] λ g = cK o -d ;

[0035] where c and d are the second coefficients, and K o is the gas logging permeability value of the reservoir core tested on the ground.

[0036] This application also provides a device for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir, including:

[0037] A model module for constructing a carbon dioxide injection rate model including matrix confining pressure permeability and starting pressure gradient;

[0038] A first test module for testing the permeability of reservoir core samples of tight sandstone reservoirs under different effective stresses to obtain a first relationship curve between the matrix confining pressure permeability and the effective stress;

[0039] Performing regression analysis on the first relationship curve to obtain the first coefficient corresponding to the matrix confining pressure permeability;

[0040] A second test module for respectively performing starting pressure gradient tests on the core samples with different matrix confining pressure permeabilities to obtain a second relationship curve between the starting pressure gradient and the matrix confining pressure permeability;

[0041] Perform a regression analysis on the second relationship curve to obtain a second coefficient corresponding to the starting pressure gradient.

[0042] A data module for collecting basic data to be input into the carbon dioxide flooding gas injection rate model.

[0043] A calculation module for inputting the basic data, the first coefficient, and the second coefficient into the carbon dioxide flooding gas injection rate model for calculation to obtain the gas injection rate of a single well.

[0044] This application also provides a device for determining the gas injection rate of a single well in an oil reservoir, including:

[0045] A memory for storing a computer-executable program for the method for determining the gas injection rate of a single well in an oil reservoir as described above.

[0046] A processor for retrieving the computer-executable program from the memory and executing the steps of the method for determining the gas injection rate of a single well in an oil reservoir.

[0047] This application also provides a storage medium storing a computer-executable program, which is used to be retrieved by a processor to execute the steps of the method for determining the gas injection rate of a single well in an oil reservoir as described above.

[0048] Advantages and beneficial effects of this application:

[0049] This application provides a method for determining the CO2 flooding gas injection rate of a single well in a low-permeability tight oil reservoir, including: constructing a carbon dioxide flooding gas injection rate model including matrix overburden permeability and starting pressure gradient; testing the permeability of reservoir core samples of a tight sandstone oil reservoir under different effective stresses to obtain a first relationship curve between the matrix overburden permeability and the effective stress; performing a regression analysis on the first relationship curve to obtain a first coefficient corresponding to the matrix overburden permeability; respectively performing starting pressure gradient tests on the core samples with different matrix overburden permeabilities to obtain a second relationship curve between the starting pressure gradient and the matrix overburden permeability; performing a regression analysis on the second relationship curve to obtain a second coefficient corresponding to the starting pressure gradient; collecting basic data to be input into the carbon dioxide flooding gas injection rate model; inputting the basic data, the first coefficient, and the second coefficient into the carbon dioxide flooding gas injection rate model for calculation to obtain the gas injection rate of a single well. When calculating the gas injection rate in this application, the matrix overburden permeability and the starting pressure gradient are considered, and it better combines the actual situation, can better optimize the carbon dioxide flooding gas injection rate, and thus improve the oilfield exploitation efficiency. Description of the Drawings

[0050] The attached drawings forming a part of this invention are used to provide a further understanding of the invention. The schematic embodiments and descriptions thereof of the invention are used to explain the invention and shall not unduly limit the invention. In the drawings:

[0051] Figure 1 is a schematic flow chart of a method for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir in this application.

[0052] Figure 2 is a schematic diagram of the pressure gradient - seepage velocity curve and the starting pressure gradient in this application;

[0053] Figure 3 is a schematic diagram of the relationship curve between permeability and starting pressure gradient in this application;

[0054] Figure 4 is a schematic diagram of the change curve of the rock permeability of Well No. 1 with the effective stress (Ph - Pi) in this application;

[0055] Figure 5 is a schematic diagram of the change curve of the rock permeability of Well No. 2 with the effective stress (Ph - Pi) in this application;

[0056] Figure 6 is a schematic diagram of the test results of the starting pressure of the matrix core of Well No. 1 injection well in this application;

[0057] Figure 7 is a schematic diagram of the test results of the starting pressure of the matrix core of Well No. 2 injection well in this application;

[0058] Figure 8 is a schematic diagram of the relationship between matrix permeability and starting pressure gradient in this application;

[0059] Figure 9 is a schematic diagram of the relative permeability curve of CO2 flooding in the matrix core of Well No. 1 injection well in this application;

[0060] Figure 10 is a schematic diagram of the relative permeability curve of CO2 flooding in the matrix core of Well No. 2 injection well in this application. Detailed Embodiments

[0061] The present invention will be described in detail below with reference to the attached drawings and in conjunction with embodiments. It should be noted that, without conflict, the embodiments in the present invention and the features in the embodiments can be combined with each other.

[0062] The following detailed descriptions are all exemplary descriptions, aiming to provide further detailed explanations for the present invention. Unless otherwise specified, all technical terms used in the present invention have the same meaning as commonly understood by those of ordinary skill in the technical field to which the present invention belongs. The terms used in the present invention are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present invention.

[0063] The traditional method for designing the injection rate of carbon dioxide flooding is relatively rough and fails to fully consider the influence of reservoir heterogeneity on the formation injection rate, resulting in the inability to achieve differential injection rate design. To improve this situation, a new mathematical model has been established. This model takes into account key factors such as reservoir physical properties, thickness heterogeneity, and starting pressure gradient in a refined manner, enabling more accurate simulation of the carbon dioxide flooding injection rate under actual geological conditions.

[0064] In the process of constructing the model, a series of important parameters obtained from physical simulation experiments are combined, including the relationship curve between the starting pressure gradient and physical properties, the relative permeability curve of oil-gas two phases, and the basic physical property parameters of formation crude oil and carbon dioxide. These parameters provide key information for in-depth understanding of reservoir characteristics and the carbon dioxide drive mechanism.

[0065] By applying this new mathematical model, it is possible to achieve differential design of the carbon dioxide flooding injection rate for different single wells. This design method is not only more comprehensive but also more practical. It significantly improves the scientificity of parameter design and further greatly enhances the development effect of carbon dioxide flooding. This has far-reaching significance for promoting the efficient development of oilfields and realizing sustainable energy utilization.

[0066] This application describes a method for determining the injection rate of a single well in an oil reservoir. This method realizes differential design of the carbon dioxide flooding injection rate for different single wells by establishing a mathematical model that comprehensively considers reservoir physical properties, thickness heterogeneity, and starting pressure gradient, and combining a number of key parameters obtained from experimental tests.

[0067] Please refer to Figure 1 As shown, a method for determining the injection rate of CO2 flooding for a single well in a low-permeability tight oil reservoir, the steps of which include:

[0068] S101 Construct a carbon dioxide flooding injection rate model including matrix overburden permeability and starting pressure gradient.

[0069] To optimize the carbon dioxide flooding injection rate, a carbon dioxide flooding injection rate model needs to be established, which comprehensively considers reservoir heterogeneity, starting pressure gradient, and stress sensitivity of the reservoir.

[0070] Reservoir heterogeneity: The properties of the reservoir are not evenly distributed, and there are differences in physical properties, thickness, etc. at different locations. This heterogeneity will affect the flow and distribution of carbon dioxide in the reservoir.

[0071] Starting pressure gradient: It is the minimum pressure gradient that enables the fluid to start flowing. In the reservoir, the starting pressure gradient is a key parameter because it determines whether the fluid will start flowing at a given pressure.

[0072] Reservoir stress sensitivity: The physical properties such as the permeability of the reservoir are affected by stress. When the stress changes, these physical properties will also change, thereby affecting the fluid flow.

[0073] Generally, the calculation formula for the gas intake intensity of a homogeneous formation without considering stress sensitivity is:

[0074]

[0075] When considering stress sensitivity, the relationship between the matrix permeability under overburden pressure and the surface permeability is:

[0076]

[0077] The relationship between the gas drive starting pressure gradient and permeability is:

[0078] λ g = cK o -d ;

[0079] Therefore, considering the permeability and thickness heterogeneity of different single-well reservoirs, and combining the stress sensitivity and starting pressure gradient commonly existing in tight sandstone oil reservoirs, a carbon dioxide flooding gas injection rate model for tight sandstone oil reservoirs was established, and its expression is:

[0080]

[0081] Among them, the bottom-hole gas injection pressure P of the gas injection i can usually be calculated and obtained according to the wellhead pressure and gas column pressure. Without considering friction, its calculation formula is as follows:

[0082] P i = P o + ρ G gh;

[0083] The area A of the injection-production well group is usually calculated and obtained according to the injection-production well spacing and row spacing. The calculation formula is as follows:

[0084] A = 4MN;

[0085] The carbon dioxide gas volume factor is usually calculated and obtained according to the gas state equation. The calculation formula is as follows

[0086]

[0087] The meanings of the symbols in the above formula are as follows:

[0088] q i : Carbon dioxide injection rate per single well, t / d;

[0089] γ: Permeability conversion coefficient under overburden pressure and atmospheric pressure, a constant related to reservoir physical properties and pressure, generally between 0.1 and 0.3;

[0090] K o : Gas logging permeability value of reservoir core measured on the ground, mD;

[0091] K σ : Overburden permeability, a variable, related to effective stress, mD;

[0092] P i : Bottom-hole pressure of gas injection for a single well, MPa;

[0093] P o : Wellhead pressure of gas injection well, MPa;

[0094] h: Reservoir burial depth, m;

[0095] P f : Formation pressure measured for a single well, MPa;

[0096] P h : Overburden pressure of the reservoir at the reservoir depth, MPa;

[0097] K rg : Relative permeability of carbon dioxide at residual oil saturation, decimal;

[0098] A: Area of injection-production well group, m2;

[0099] M: Well spacing, m;

[0100] N: Row spacing, m;

[0101] B g : Carbon dioxide volume coefficient, decimal;

[0102] P sc : Pressure under standard conditions, MPa

[0103] T sc T: Temperatures under standard conditions and actual reservoir temperature respectively, K;

[0104] Z: Deviation factor of carbon dioxide under actual reservoir temperature and pressure, dimensionless decimal;

[0105] μ g:Viscosity of carbon dioxide under formation conditions, mPa·s;

[0106] ρ G and ρ g : Average densities of carbon dioxide from wellhead to bottomhole (in the wellbore) and under formation conditions, kg / m3;

[0107] h i : Effective thickness of the reservoir of a single well, m;

[0108] r w : Well diameter, m;

[0109] a, b, c, d: Constants obtained through experimental tests.

[0110] S102 conducts permeability tests on reservoir core samples of a tight sandstone reservoir under different effective stresses to obtain the first relationship curve between the matrix overburden permeability and the effective stress.

[0111] Specifically, according to the Petroleum and Natural Gas Industry Standard SY / T 6385-2016 of the People's Republic of China, "Methods for Determining Rock Porosity and Permeability under Overburden Pressure", permeability tests on reservoir cores under different effective stresses are carried out to obtain the first relationship curve.

[0112] S103 conducts regression analysis on the first relationship curve to obtain the first coefficients corresponding to the matrix overburden permeability.

[0113] The first coefficients include coefficient a and coefficient b.

[0114] In this application, by conducting regression analysis on the first relationship curve, the corresponding equation can be found to describe the relationship between the effective stress and the matrix overburden permeability.

[0115] Through regression analysis, each coefficient in the equation can be obtained. Among them, the coefficient directly related to the matrix overburden permeability is called the second coefficient.

[0116] S104 conducts starting pressure gradient tests on the core samples with different matrix overburden permeabilities respectively to obtain the second relationship curve between the starting pressure gradient and the matrix overburden permeability.

[0117] The steps for conducting the starting pressure gradient test are as follows:

[0118] First, after the core is dried, it is put into a physical simulation device and evacuated: In this step, the core sample is dried to remove the moisture in it. Then, the dried core is put into the physical simulation device. This device is used to simulate reservoir conditions.

[0119] Secondly, the model is heated to the test reservoir temperature: In this step, the model is heated to the temperature of the test reservoir to simulate the temperature conditions of the actual reservoir. Meanwhile, the end backpressure is used to test the formation pressure of the reservoir. Then, carbon dioxide is injected into the core to simulate the gas injection process in the actual reservoir.

[0120] Thirdly, inject carbon dioxide in a constant pressure mode: In this step, carbon dioxide is injected into the core in a constant pressure mode. The initial injection pressure is set between 105% and 110% of the end backpressure. At fixed time intervals, the outlet flow rate is measured. When the relative deviation of the flow rates measured three times in a row is less than 2%, the flow rate can be considered to have reached a steady state. This step can determine the flow rate stability of the core under constant pressure.

[0121] Then, change the injection pressure to obtain different steady seepage velocities under different pressure gradients: In this step, the injection pressure is changed, and the value increased each time is 5% to 10% of the end pressure. According to the previous measurement method, the steady flow rate is determined again. Through this step, different steady seepage velocities under different pressure gradients can be obtained. This provides information about the seepage characteristics of the core under different pressure conditions.

[0122] Then, based on multiple groups of pressure gradients and seepage velocities of a single core, draw a curve with the pressure gradient on the abscissa and the seepage velocity on the ordinate, project it in a two-dimensional coordinate, fit the curve, and obtain the fluid pressure gradient corresponding to the outlet seepage velocity of 0 as the starting pressure gradient of the sample, as Figure 2 shown.

[0123] Finally, according to the starting pressure gradient and the seepage velocity, draw a second relationship curve, as Figure 3 shown.

[0124] S105 performs a regression analysis on the second relationship curve to obtain a second coefficient corresponding to the starting pressure gradient.

[0125] The second coefficient includes coefficient c and coefficient d.

[0126] In this application, performing a regression analysis on the second relationship curve can find the corresponding equation to describe the relationship between the starting pressure gradient and other parameters.

[0127] Through the regression analysis, each coefficient in the equation can be obtained. Among them, the coefficient directly related to the starting pressure gradient is called the second coefficient.

[0128] S106 collects the basic data to be input into the carbon dioxide flooding gas injection velocity model.

[0129] The basic data includes:

[0130] I. Thickness, matrix permeability, reservoir burial depth, well spacing between injection and production wells, and row spacing of different single wells:

[0131] Thickness: Refers to the thickness of the oil reservoir, usually obtained through geological logging.

[0132] Matrix permeability: Represents the ability of the rock to allow fluid to pass through. High permeability means the rock allows fluid to pass through more easily.

[0133] Reservoir burial depth: The depth of the oil reservoir from the ground surface.

[0134] Well spacing between injection and production wells: The distance between the injection well and the production well.

[0135] Row spacing: The distance between production wells.

[0136] II. Wellhead pressure of different injection wells and average formation pressure of different injection well groups:

[0137] Wellhead pressure: The pressure at the wellhead, usually measured by a wellhead pressure gauge.

[0138] Average formation pressure of injection well group: The average pressure of the formation within a certain injection well group. This is usually determined based on the latest pressure measurement results or the latest average pressure measurement of production wells within the well group.

[0139] III. Carbon dioxide density and viscosity under reservoir conditions:

[0140] These parameters are usually based on the temperature and pressure of the reservoir. By referring to the corresponding carbon dioxide viscosity and density charts, these values can be directly obtained.

[0141] IV. Carbon dioxide volume coefficient:

[0142] The volume coefficient is a parameter that describes the volume change of gas between the underground state and the ground standard state. It is usually obtained by using the gas state equation.

[0143] V. Carbon dioxide relative permeability at residual oil saturation:

[0144] Relative permeability describes the flow ability of a certain phase of fluid (such as carbon dioxide) in a porous medium (such as reservoir rock). Especially in the presence of another phase of fluid (such as crude oil).

[0145] Carbon dioxide - crude oil relative permeability curve: This curve describes how the relative permeability of carbon dioxide and crude oil in a porous medium changes with saturation. Through this curve, the relative permeability of carbon dioxide at residual oil saturation can be obtained.

[0146] S107 Input the basic data, the first coefficient, and the second coefficient into the carbon dioxide flooding injection rate model for calculation to obtain the injection rate of a single well.

[0147] The obtained gas injection rate can guide actual engineering operations and help engineers determine the rate to be adopted during the actual carbon dioxide injection process.

[0148] The gas injection rate may also need to be adjusted and optimized in combination with actual engineering constraints, economic factors, etc.

[0149] This application also provides a device for determining the gas injection rate of a single well in a low-permeability tight oil reservoir, including:

[0150] A model module for constructing a gas injection rate model for carbon dioxide flooding that includes matrix overburden permeability and starting pressure gradient;

[0151] A first test module for testing the permeability of reservoir core samples of a tight sandstone reservoir under different effective stresses to obtain a first relationship curve between the matrix overburden permeability and the effective stress;

[0152] Performing regression analysis on the first relationship curve to obtain a first coefficient corresponding to the matrix overburden permeability;

[0153] A second test module for respectively performing starting pressure gradient tests on the core samples with different matrix overburden permeabilities to obtain a second relationship curve between the starting pressure gradient and the matrix overburden permeability;

[0154] Performing regression analysis on the second relationship curve to obtain a second coefficient corresponding to the starting pressure gradient;

[0155] A data module for collecting basic data to be input into the gas injection rate model for carbon dioxide flooding;

[0156] A calculation module for inputting the basic data, the first coefficient, and the second coefficient into the gas injection rate model for carbon dioxide flooding for calculation to obtain the gas injection rate of a single well.

[0157] This application also provides an equipment for determining the gas injection rate of a single well in an oil reservoir, including:

[0158] A memory for storing a computer-executable program for the method for determining the gas injection rate of a single well in an oil reservoir as described above;

[0159] A processor for retrieving the computer-executable program from the memory and executing the steps of the method for determining the gas injection rate of a single well in an oil reservoir.

[0160] This application also provides a storage medium storing a computer-executable program, and this computer-executable program is used to be retrieved and executed by a processor to execute the steps of the method for determining the gas injection rate of a single well in an oil reservoir as described above.

[0161] Experimental description of the technical solution of this application:

[0162] This experiment involves the detailed parameters of two gas injection wells (Well No. 1 and Well No. 2) and the related test results. The following is an overview of these contents:

[0163] For an ultra-low permeability reservoir A, the reservoir temperature is 80°C, and carbon dioxide is injected in a square inverted nine-spot well pattern with a well spacing and row spacing of 300 m.

[0164] Among them, Gas Injection Well No. 1: well depth is 2500 m, overburden pressure is 53.1 MPa, reservoir thickness is 10.0 m, matrix gas-measured permeability is 0.41 mD, porosity is 9.5%, the formation pressure measured in the past six months shows 23.0 MPa, the gas injection wellhead pressure is 18 MPa, the bottom-hole pressure is 45 MPa, the average density of carbon dioxide in the reservoir is 0.46 g / cm3, viscosity is 0.05 mPa·s, gas deviation factor is 0.90, and well diameter is 0.139 m.

[0165] Gas Injection Well No. 2: well depth is 2450 m, overburden pressure is 52.0 MPa, reservoir thickness is 12.0 m, matrix gas-measured permeability is 0.24 mD, porosity is 10.4%, the formation pressure measured in the past six months shows 22.5 MPa, the gas injection wellhead pressure is 16.0 MPa, the bottom-hole pressure is 43 MPa, the average density of carbon dioxide in the reservoir is 0.42 g / cm3, viscosity is 0.045 mPa·s, gas deviation factor is 0.92, and well diameter is 0.139 m.

[0166] According to the Petroleum and Natural Gas Industry Standard SY / T 6385-2016 of the People's Republic of China, "Determination Method of Rock Porosity and Permeability under Overburden Pressure", the permeabilities of cores of two different gas injection wells under different effective stresses were tested, the relationship curve between matrix overburden permeability and effective stress was obtained, and coefficients a and b were regressed.

[0167] As Figure 4 shown, for Well No. 1, the coefficient a is 0.7281 and b is 0.554, and the true permeability of the matrix core under an overburden pressure of 53.1 MPa and a formation pressure of 23.0 MPa is 0.11 mD.

[0168] As Figure 5 shown, for Well No. 2, the coefficient a is 0.3875 and b is 0.658, and the true permeability of the matrix core under an overburden pressure of 52.0 MPa and a formation pressure of 22.5 MPa is 0.041 mD.

[0169] The carbon dioxide starting pressure gradient test of cores with different matrix permeabilities in the target area was carried out, the relationship curve between the starting pressure gradient and matrix permeability was obtained, and coefficients c and d were obtained.

[0170] AsFigure 6 As shown, the starting pressure gradient of CO₂ flooding in Well 1# is 0.34 MPa / m

[0171] As Figure 7 shown, the starting pressure gradient of CO₂ flooding in Well 2# is 0.53 MPa / m

[0172] As Figure 8 shown, following the same process and method, the starting pressure gradient of CO₂ flooding in cores with reservoir permeability ranging from 0.03 to 0.3 mD was tested, and the relationship curve between matrix permeability and starting pressure gradient was established, obtaining regression coefficients c and d as 0.1148 and 0.487 respectively.

[0173] Obtain basic physical property data, production performance data, and CO₂ physical property data of the test area.

[0174] Among them, the CO₂ volume coefficient is calculated according to the formula, where the deviation factor Z takes a value of 0.9.

[0175]

[0176] According to the reservoir temperature and pressure of Well 1# and Well 2#, the CO₂ volume coefficients of injection wells 1# and 2# are 0.0070 and 0.0074 respectively.

[0177] As Figure 9 and Figure 10 shown, the relative permeability of CO₂ at residual oil saturation is obtained from the CO₂ - crude oil relative permeability curve, which are 0.750 and 0.675 respectively.

[0178] According to the data obtained above, substituting them into the mathematical model, the optimal single - well gas injection rates of Well 1# and Well 2# are 34.3 t / d and 19.8 t / d respectively.

[0179] The results show that: the differences in reservoir physical properties have an obvious impact on the single - well gas injection capacity, and the gas injection rates of different single wells in the same reservoir need to be designed differently.

[0180] As is known by common technical knowledge, the present invention can be implemented by other embodiments that do not depart from its spirit or essential characteristics. Therefore, the above - disclosed embodiments are illustrative in all aspects and are not the only ones. All changes within the scope of the present invention or within the scope equivalent to the present invention are encompassed by the present invention.

[0181] Those skilled in the art should understand that the embodiments of the present invention can be provided as a method, a system, or a computer program product. Therefore, the present invention can take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware aspects. Moreover, the present invention can take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) that contain computer-usable program code.

[0182] The present invention is described with reference to the flowcharts and / or block diagrams of methods, apparatuses (systems), and computer program products according to embodiments of the present invention. It should be understood that each flow and / or block in the flowchart and / or block diagram, and the combination of flows and / or blocks in the flowchart and / or block diagram, can be realized by computer program instructions. These computer program instructions can be provided to the processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing devices to generate a machine, such that the instructions executed by the processor of the computer or other programmable data processing devices generate means for realizing the functions specified in one Figure 1 one flow or multiple flows and / or blocks Figure 1 or multiple blocks.

[0183] These computer program instructions can also be stored in a computer-readable memory that can direct a computer or other programmable data processing device to work in a specific manner, such that the instructions stored in the computer-readable memory generate a manufactured article including instruction means that realizes the functions specified in one Figure 1 one flow or multiple flows and / or blocks Figure 1 or multiple blocks.

[0184] These computer program instructions can also be loaded onto a computer or other programmable data processing device, such that a series of operation steps are executed on the computer or other programmable device to generate a computer-implemented process, so that the instructions executed on the computer or other programmable device provide steps for realizing the functions specified in one Figure 1 one flow or multiple flows and / or blocks Figure 1 or multiple blocks.

[0185] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit them. Although the present invention has been described in detail with reference to the above embodiments, those of ordinary skill in the art should understand that: still can modify the specific implementation manners of the present invention or make equivalent replacements, and any modification or equivalent replacement that does not depart from the spirit and scope of the present invention should be covered within the protection scope of the claims of the present invention.

Claims

1. A method for determining the injection rate of CO2 in a single well of a low-permeability tight oil reservoir, characterized in that, Including: Construct a carbon dioxide flooding gas injection velocity model that includes matrix overburden permeability and starting pressure gradient; Test the permeability of reservoir core samples in a tight sandstone reservoir under different effective stresses to obtain a first relationship curve between the matrix overburden permeability and the effective stress; Conduct regression analysis on the first relationship curve to obtain a first coefficient corresponding to the matrix overburden permeability; Conduct starting pressure gradient tests on the core samples with different matrix overburden permeabilities respectively to obtain a second relationship curve between the starting pressure gradient and the matrix overburden permeability; Conduct regression analysis on the second relationship curve to obtain a second coefficient corresponding to the starting pressure gradient; Collect basic data to be input into the carbon dioxide flooding gas injection velocity model; Input the basic data, the first coefficient, and the second coefficient into the carbon dioxide flooding gas injection velocity model for calculation to obtain the gas injection velocity of a single well.

2. The method for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir according to claim 1, characterized in that The carbon dioxide flooding gas injection velocity model has the following expression: where q i is the single - well carbon dioxide injection rate, K o is the measured core permeability value of the reservoir rock in surface testing, a and b are the first coefficients, c and d are the second coefficients, P h is the overburden pressure of the reservoir at the reservoir depth, P f is the formation pressure of single - well testing, K rg is the relative permeability of carbon dioxide at residual oil saturation, P i is the bottom - hole pressure of single - well gas injection, P f is the formation pressure of single - well testing, A is the area of the injection - production well group, r w is the wellbore diameter, ρ g is the average density of carbon dioxide under formation conditions, h i is the effective thickness of the single - well reservoir, B g is the volume coefficient of carbon dioxide, μ g is the viscosity of carbon dioxide under formation conditions.

3. The method for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir according to claim 1, characterized in that Conducting starting pressure gradient tests on the core samples with different matrix overburden permeabilities respectively includes: Dry the core samples and place them in a physical simulation device for vacuum treatment; Heat the physical simulation device to the temperature of the test reservoir and inject carbon dioxide at a constant pressure in the physical simulation device; Change the injection pressure when the flow rate is stable; Based on multiple pressure gradients, obtain seepage velocities corresponding to different pressure gradients; According to the multiple pressure gradients and the seepage velocities, plot a third relationship curve between the pressure gradient and the seepage velocity; Project in a two-dimensional coordinate system, fit the third relationship curve, and obtain that the fluid pressure gradient corresponding to the zero outlet seepage velocity is the starting pressure gradient of the core sample.

4. The method for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir according to claim 1, wherein Based on multiple pressure gradients, obtaining seepage velocities corresponding to different pressure gradients includes: The increase value of each pressure gradient is 5%-10% of the end pressure.

5. The method for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir according to claim 1, characterized in that The basic data includes: The thickness, matrix permeability, oil layer burial depth, well spacing, and row spacing of different single wells; The wellhead pressure of different gas injection wells and the average formation pressure of different gas injection well groups; The density and viscosity of carbon dioxide under reservoir conditions; The carbon dioxide volume coefficient and the relative permeability of carbon dioxide under residual oil saturation.

6. The method for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir according to claim 1, wherein The expression of the first relationship curve: Among them, K σ is the overburden permeability, K o is the gas logging permeability value of the reservoir rock core in the ground test, a and b are the first coefficients, P f is the formation pressure for single well test, P h is the overlying rock pressure of the reservoir at the reservoir depth.

7. A method for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir according to claim 1, characterized in that The expression of the second relationship curve: λ g = cK o -d ; where c and d are second coefficients, and K o is the gas permeability value of the reservoir core measured during surface testing.

8. A device for determining the CO2 injection rate of a single well in a low-permeability tight oil reservoir, characterized in that, Including: A model module for constructing a carbon dioxide flooding gas injection velocity model that includes matrix overburden permeability and starting pressure gradient; A first test module for testing the permeability of reservoir core samples in a tight sandstone reservoir under different effective stresses to obtain a first relationship curve between the matrix overburden permeability and the effective stress; Conduct regression analysis on the first relationship curve to obtain a first coefficient corresponding to the matrix overburden permeability; A second test module for conducting starting pressure gradient tests on the core samples with different matrix overburden permeabilities respectively to obtain a second relationship curve between the starting pressure gradient and the matrix overburden permeability; Conduct regression analysis on the second relationship curve to obtain a second coefficient corresponding to the starting pressure gradient; A data module for collecting basic data to be input into the carbon dioxide flooding gas injection velocity model; A calculation module, configured to input the basic data, the first coefficient, and the second coefficient into the carbon dioxide flooding gas injection rate model for calculation to obtain the gas injection rate of a single well.

9. An equipment for determining the gas injection rate of a single well in a reservoir, characterized in that It includes: A memory, configured to store a computer executable program for the method for determining the CO2 flooding gas injection rate of a single well in a low-permeability tight oil reservoir according to any one of claims 1 to 7; A processor, configured to retrieve the computer executable program from the memory and execute the steps of the method for determining the gas injection rate of a single well in the oil reservoir.

10. A storage medium, characterized in that, Stored with a computer executable program, which is used to be retrieved and executed by a processor to execute the steps of the method for determining the CO2 flooding gas injection rate of a single well in a low-permeability tight oil reservoir according to any one of claims 1 to 7.

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