Method and system for determining effective development scheme of shale oil reservoir

Abstract

The invention discloses a method and a system for determining an effective development scheme of a shale oil reservoir, and the method comprises the steps: obtaining an effective development scheme of the shale oil reservoir based on an actual stratum and development parameters of a to-be-researched region; establishing a multi-area coupling seepage mathematical model for representing the nonlinear seepage rules of different pore medium areas, and forming a yield calculation model of different fracturing sections of the shale oil reservoir horizontal well, so as to establish a compact oil reservoir yield calculation model about the effective utilization range of the reservoir, and form a calculation scheme of the accumulated yield of the oil reservoir at different development moments; and determining an optimal development scheme by using a calculation scheme of the accumulated oil reservoir yield at different development moments. According to the method, the recovery degree of shale oil volume fracturing development is effectively improved.

Description

Technical Field

[0001] The present invention relates to the technical field of unconventional oil and gas field development, and in particular to a method and system for determining an effective development plan for a shale oil reservoir. Background Art

[0002] Shale oil reservoirs have small pore throats, weak permeability, and insufficient formation energy, which restricts their effective development. In the early development process, many oil fields in my country, based on the development of conventional oil reservoirs, combined with the relevant development experience of low permeability oil reservoirs, carried out measures such as densification of injection and production well networks, but the phenomenon of "no injection and no production" was generally seen, and shale oil reservoirs have reached the point where water drive is ineffective. Due to the complex accumulation mechanism and storage space of shale oil, diverse pore types, and the development of micro-nanoscale pores, as well as the complex migration mechanism of shale oil, it is difficult to obtain industrial oil flow under the conventional development model, and only horizontal wells and multi-stage fracturing technology can be relied on to achieve efficient development. At present, the main research directions of shale oil development in my country are concentrated on long horizontal well development and volume fracturing technology. It mainly includes the fracturing process of "fast drilling bridge plug + multi-cluster perforation fracturing" and "mixed fracturing fluid + small-size ceramsite plus sand".

[0003] As volume fracturing technology becomes more mature, shale oil reservoirs have become the main research direction for oil and gas field development in recent years. The complex fracture network formed by volume fracturing can greatly increase the production of a single well. Oil trials and production trials have been carried out in shale oil reservoirs such as the Junggar Basin and the Ordos Basin. In the early stages of development, most horizontal wells produced significantly more crude oil per day than vertical wells, with production generally 3 to 5 times higher. The initial production capacity of horizontal wells in the Jimusar Depression can reach 10 to 15 times that of vertical wells.

[0004] As for the exploitation method of shale oil wells, depletion development is the main method at home and abroad. In order to recover costs as quickly as possible, a pressure-release production development model is often chosen. However, due to the stress sensitivity of the reservoir, the permeability is damaged and even artificial fractures are closed. The production decreases rapidly, and the decline rate in the first year can reach 70%.

[0005] Many scholars have clarified the nonlinear seepage characteristics of unconventional reservoirs through a large number of indoor experiments and verified the stress sensitivity characteristics of unconventional reservoirs. Xu Xinli et al. studied the stress sensitivity of fracture cores. The stress sensitivity of microfracture cores is very weak, and the permeability change rate is less than 30%. The sensitivity curve is divided into two stages: the permeability decreases by more than 20% in the first stage, which is mainly due to pseudo-plastic deformation of microfractures under pressure closure; the permeability decreases by less than 10% in the second stage, which is mainly due to elastic deformation of rock skeleton particles under compression. The net stress of the actual reservoir is mostly in this stage. Based on indoor experiments, Fang Pingliang et al. analyzed the stress sensitivity characteristics of multiple media such as pores, fractures and holes in tight reservoirs, and formed a fluid-solid coupling seepage theory. Wei Yi and others combined seismic interpretation, well logging analysis, core thin sections and other static data, and divided the reservoir storage and permeability patterns into four types: multi-level fracture-pore type, large fracture-pore type, micro-fracture-pore type and pore type based on changes in fracture type, scale and degree of development. Different storage and permeability patterns have different combination types, showing different seepage characteristics and production capacity characteristics.

[0006] However, most of the current stress sensitivity research is conducted on low-permeability / ultra-low-permeability reservoirs. Due to the strong stress sensitivity characteristics of different porous media in shale reservoirs, the stress sensitivity characteristics are obvious during the conventional depressurization production process, and the production decreases sharply. Therefore, a scientific and reasonable drainage system is urgently needed to increase the single-well production of shale reservoirs. Summary of the invention

[0007] The purpose of the present invention is to provide an effective development scheme that takes into account the strong stress sensitivity characteristics of different porous media in shale oil reservoirs, thereby increasing the single well production of shale oil reservoirs.

[0008] In order to solve the above technical problems, an embodiment of the present invention provides a method for determining an effective development plan for shale oil reservoirs, comprising: based on the actual formation and development parameters of the area to be studied, establishing a multi-zone coupled seepage mathematical model that characterizes the nonlinear seepage laws of different porous media regions and forming a production calculation model for different fracturing sections of horizontal wells in shale oil reservoirs, thereby establishing a tight oil reservoir production calculation model for the effective utilization range of the reservoir to form a calculation plan for the cumulative production of the reservoir at different development times; using the calculation plan for the cumulative production of the reservoir at different development times to determine the best development plan.

[0009] Preferably, the calculation scheme of the cumulative production of the oil reservoir at different development moments includes the following steps: the first step is to establish a multi-zone coupled seepage model of the shale oil reservoir and determine the flow field model parameters of the area to be studied; the second step is to calculate the producing radius and the cumulative production of the oil reservoir at the first development moment under the multi-zone coupled seepage model by using the multi-zone coupled seepage mathematical model, the production calculation model of different fracturing stages and the cumulative production calculation model of the tight oil reservoir according to the actual formation and development parameters of the area to be studied; the third step is to calculate the flow field model parameters of the multi-zone coupled seepage model under the elliptical flow field, based on which, combined with the cumulative production of the oil reservoir at the first development moment, the multi-zone coupled seepage mathematical model is used to calculate the average formation pressure of each porous medium region; the fourth step is to correct the permeability and starting pressure gradient of each porous medium according to the average formation pressure of each porous medium region and considering the stress sensitivity, so as to return to the second step to calculate the cumulative production of the oil reservoir at the second development moment according to the corrected permeability of each porous medium, and then obtain the producing radius and the cumulative production of the oil reservoir at the different development moments.

[0010] Preferably, the tight oil reservoir production calculation model is expressed using the following expression:

[0011]

[0012] Among them, t represents the development time, n represents the total number of development time, Q t represents the production at time t, ρ represents the fluid density, φ represents the pore volume at time t, and r w represents the wellbore radius, R t represents the producing radius, r represents the radius, h represents the reservoir thickness, and e represents the original state of the formation, wherein the production calculation model of different fracturing stages is expressed by the following expression:

[0013]

[0014] Where i represents the serial number of the fracturing stage, q i represents the production of the ith fracturing stage at time t, p ei represents the pressure at the outer boundary of the matrix region of the ith fracturing stage, p wi represents the given bottom hole pressure of the ith fracturing stage, G ni ' represents the starting pressure gradient of the fracture network area in the i-th fracturing stage under the multi-zone coupled seepage model, r ni represents the equivalent radius of the outer boundary of the fracture network area of ​​the i-th fracturing stage, r fi represents the equivalent radius of the outer boundary of the main fracture of the ith fracturing stage, G mi ' represents the starting pressure gradient of the matrix region of the i-th fracturing stage under the multi-zone coupled seepage model, rei represents the radius of the outer boundary of the matrix region of the i-th fracturing stage, S i represents the area of ​​the overlapped area of ​​adjacent fracture segments of the ith fracturing segment, a i represents the long axis of the elliptical flow field of the multi-zone coupled seepage flow field in the z plane, b i Represents the short axis of the elliptical flow field of the multi-zone coupled seepage flow field in the z plane, R fi represents the equivalent seepage resistance of the main fracture area of ​​the i-th fracturing stage, R ni represents the equivalent seepage resistance of the fracture network area of ​​the i-th fracturing stage, R mi represents the equivalent seepage resistance of the matrix region of the i-th fracturing stage.

[0015] Preferably, the multi-zone coupled seepage mathematical model includes: basic differential equations and boundary conditions of the main fracture area, and pressure and flow models at any point in the main fracture area; basic differential equations and boundary conditions of the fracture network area, a starting pressure gradient model, and pressure and flow models at any point in the fracture network area; and basic differential equations and boundary conditions of the matrix area, a starting pressure gradient model, and pressure and flow models at any point in the matrix area.

[0016] Preferably, in the step of determining the optimal development scheme using the calculation scheme of the cumulative production of the oil reservoir at the different development moments, it includes: determining the optimal pressure control cycle according to the cumulative production of the oil reservoir at the different development moments; and determining the optimal pressure control mode by respectively calculating the cumulative production of the oil reservoir under different pressure control modes under the optimal pressure control cycle.

[0017] Preferably, the step of determining the optimal pressure control period according to the cumulative production of the reservoir at different development moments includes: given a bottom hole pressure sequence under different pressure control periods, using the calculation scheme of the cumulative production of the reservoir at different development moments, respectively calculating the cumulative production of the reservoir under each pressure control period, the amplitude of each pressure element in the bottom hole pressure sequence is reduced in a step-by-step manner according to a preset number of elements per interval; and taking the pressure control period corresponding to the maximum value of the cumulative production of the reservoir as the optimal pressure control period.

[0018] Preferably, in the step of determining the optimal pressure control mode by respectively calculating the cumulative production of the reservoir under different pressure control modes under the optimal pressure control cycle, the step includes: given the bottom hole pressure sequence under different pressure control modes, using the calculation scheme of the cumulative production of the reservoir under the different development moments, respectively calculating the cumulative production of the reservoir under each pressure control mode, the different pressure control modes including constant rate pressure reduction, fast first then slow, and slow first then fast, the amplitude of each pressure element in the bottom hole pressure sequence is reduced according to a different number of elements per interval; the pressure control mode corresponding to the maximum value of the cumulative production of the reservoir is taken as the optimal pressure control mode.

[0019] Preferably, the actual formation and development parameters include: porosity of different media areas, matrix permeability, formation thickness, original viscosity, rock compressibility, formation fluid compressibility, original formation pressure, bottom hole pressure under specific conditions, fracture half-length, main fracture width, short axis length of fracture network transformation zone, wellbore radius, horizontal well length and number of volume fracturing sections.

[0020] On the other hand, an embodiment of the present invention provides a computer-readable storage medium comprising a series of instructions for executing the method steps as described above.

[0021] In addition, an embodiment of the present invention also provides a system for determining an effective development plan for shale oil reservoirs, including: a cumulative production calculation plan forming module, which is configured to establish a multi-zone coupled seepage mathematical model that characterizes the nonlinear seepage laws of different porous media regions based on the actual formation and development parameters of the area to be studied and form a production calculation model for different fracturing sections of horizontal wells in shale oil reservoirs, thereby establishing a tight oil reservoir production calculation model for the effective utilization range of the reservoir to form a calculation plan for the cumulative production of the reservoir at different development times; a development plan forming module, which is configured to use the calculation plan for the cumulative production of the reservoir at different development times to determine the best development plan.

[0022] Compared with the prior art, one or more embodiments of the above scheme may have the following advantages or beneficial effects:

[0023] The present invention proposes a method and system for determining an effective development plan for shale oil reservoirs, which belongs to the technical field of unconventional oil and gas field development, and particularly relates to an effective development method for controlling bottom hole pressure in shale oil reservoirs. Specifically for the multi-scale flow medium formed by volume fracturing of shale oil reservoirs, firstly, through indoor core displacement experiments, the stress sensitivity characteristics of shale matrix cores and semi-filled / fully filled fracture cores are revealed (semi-filled / fully filled fracture cores correspond to artificial fractures and micro fractures, respectively), and the characterization formula of the equivalent permeability of shale oil in different porous media is established; secondly, according to the seepage characteristics of different porous media, a multi-zone coupled seepage mathematical model characterizing matrix-micro fractures-artificial fractures is established; thirdly, through multi-zone coupling solution, a non-steady-state production prediction method for shale oil reservoirs is derived, and the law of full life cycle production decline is explained; finally, through the analysis of influencing factors, a step-by-step pressure reduction production method is proposed, and the pressure reduction speed and pressure reduction cycle are optimized. The present invention can economically and effectively improve the recovery degree of shale oil volume fracturing development on the basis of the existing pressure release production method.

[0024] Specifically, the present invention effectively suppresses the damage of strong stress sensitivity to shale oil reservoirs during the development process by controlling the bottom hole pressure in the exploitation stage, and increases the imbibition displacement effect, showing the development effect of "increasing oil and reducing water", and achieving an increase in the degree of recovery. In addition, the present invention optimizes the pressure control time and pressure control mode, and can increase the degree of recovery by 3.74% compared with the pressure release production and development mode. In this way, the present invention targets the multi-scale seepage characteristics of shale oil reservoirs after volume fracturing, and improves the degree of recovery of shale oil by adjusting the pressure reduction rate under existing development process conditions. It is low-cost, effective and practical, and has strong operability, and can guide the effective development of shale oil.

[0025] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0026] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0027] Figure 1 A diagram showing the steps of a method for determining an effective development plan for a shale oil reservoir according to an embodiment of the present application.

[0028] Figure 2 This is a schematic diagram of the relationship between effective stress and permeability of different porous media in the method for determining an effective development plan for shale oil reservoirs in an embodiment of the present application.

[0029] Figure 3 It is a schematic diagram of a multi-zone coupled seepage model in a method for determining an effective development plan for a shale oil reservoir according to an embodiment of the present application.

[0030] Figure 4 This is a schematic diagram of the full life cycle production prediction results fitted in the method for determining an effective development plan for a shale oil reservoir in an embodiment of the present application.

[0031] Figure 5 A schematic diagram of production changes in effective development of shale oil under pressure control in a method for determining an effective development plan for a shale oil reservoir in an embodiment of the present application.

[0032] Figure 6 A schematic diagram of bottom hole flow pressure curves given for different development modes in the method for determining an effective development plan for a shale oil reservoir according to an embodiment of the present application.

[0033] Figure 7A schematic diagram of cumulative production curves of different development modes in the method for determining an effective development plan for a shale oil reservoir according to an embodiment of the present application.

[0034] Figure 8 This is a schematic diagram of the structure of a system for determining an effective development plan for a shale oil reservoir according to an embodiment of the present application. DETAILED DESCRIPTION

[0035] The following will describe the implementation methods of the present invention in detail with reference to the accompanying drawings and embodiments, so that the implementation process of how the present invention applies technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that as long as there is no conflict, the various embodiments of the present invention and the various features in the embodiments can be combined with each other, and the technical solutions formed are all within the protection scope of the present invention.

[0036] In addition, the steps shown in the flowchart of the accompanying drawings can be executed in a computer system such as a set of computer executable instructions. Also, although a logical sequence is shown in the flowchart, in some cases, the steps shown or described can be performed in a sequence different from that here.

[0037] The terms used herein are only for describing specific embodiments and are not intended to limit exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms "one", "one" and "item" used herein are also intended to include plural numbers. It should also be understood that the terms "include" and / or "comprise" used herein specify the existence of stated features, integers, steps, operations, units and / or components, without excluding the existence or addition of one or more other features, integers, steps, operations, units, components and / or combinations thereof.

[0038] Shale oil reservoirs have small pore throats, weak permeability, and insufficient formation energy, which restricts their effective development. In the early development process, many oil fields in my country, based on the development of conventional oil reservoirs, combined with the relevant development experience of low permeability oil reservoirs, carried out measures such as densification of injection and production well networks, but the phenomenon of "no injection and no production" was generally seen, and shale oil reservoirs have reached the point where water drive is ineffective. Due to the complex accumulation mechanism and storage space of shale oil, diverse pore types, and the development of micro-nanoscale pores, as well as the complex migration mechanism of shale oil, it is difficult to obtain industrial oil flow under the conventional development model, and only horizontal wells and multi-stage fracturing technology can be relied on to achieve efficient development. At present, the main research directions of shale oil development in my country are concentrated on long horizontal well development and volume fracturing technology. It mainly includes the fracturing process of "fast drilling bridge plug + multi-cluster perforation fracturing" and "mixed fracturing fluid + small-size ceramsite plus sand".

[0039] As volume fracturing technology becomes more mature, shale oil reservoirs have become the main research direction for oil and gas field development in recent years. The complex fracture network formed by volume fracturing can greatly increase the production of a single well. Oil trials and production trials have been carried out in shale oil reservoirs such as the Junggar Basin and the Ordos Basin. In the early stages of development, most horizontal wells produced significantly more crude oil per day than vertical wells, with production generally 3 to 5 times higher. The initial production capacity of horizontal wells in the Jimusar Depression can reach 10 to 15 times that of vertical wells.

[0040] As for the exploitation method of shale oil wells, depletion development is the main method at home and abroad. In order to recover costs as quickly as possible, a pressure-release production development model is often chosen. However, due to the stress sensitivity of the reservoir, the permeability is damaged and even artificial fractures are closed. The production decreases rapidly, and the decline rate in the first year can reach 70%.

[0041] Many scholars have clarified the nonlinear seepage characteristics of unconventional reservoirs through a large number of indoor experiments and verified the stress sensitivity characteristics of unconventional reservoirs. Xu Xinli et al. studied the stress sensitivity of fracture cores. The stress sensitivity of microfracture cores is very weak, and the permeability change rate is less than 30%. The sensitivity curve is divided into two stages: the permeability decreases by more than 20% in the first stage, which is mainly due to pseudo-plastic deformation of microfractures under pressure closure; the permeability decreases by less than 10% in the second stage, which is mainly due to elastic deformation of rock skeleton particles under compression. The net stress of the actual reservoir is mostly in this stage. Based on indoor experiments, Fang Pingliang et al. analyzed the stress sensitivity characteristics of multiple media such as pores, fractures and holes in tight reservoirs, and formed a fluid-solid coupling seepage theory. Wei Yi and others combined seismic interpretation, well logging analysis, core thin sections and other static data, and divided the reservoir storage and permeability patterns into four types: multi-level fracture-pore type, large fracture-pore type, micro-fracture-pore type and pore type based on changes in fracture type, scale and degree of development. Different storage and permeability patterns have different combination types, showing different seepage characteristics and production capacity characteristics.

[0042] However, most of the current stress sensitivity research is conducted on low-permeability / ultra-low-permeability reservoirs. Due to the strong stress sensitivity characteristics of different porous media in shale reservoirs, the stress sensitivity characteristics are obvious during the conventional depressurization production process, and the production decreases sharply. Therefore, a scientific and reasonable drainage system is urgently needed to increase the single-well production of shale reservoirs.

[0043] In order to solve the problems in the above-mentioned background technology, the embodiments of the present application propose a method and system for determining an effective development plan for shale oil reservoirs. The method and system target the multi-scale complex flow characteristics of matrix-lamina-artificial fractures formed by volume fracturing development of shale oil reservoirs, carry out core displacement experiments of different flow media of matrix cores, cores containing lamina fractures, and cores through fractures, and establish a production prediction method for shale oil reservoirs that considers stress sensitivity characteristics; finally, with the pursuit of the highest recovery degree in the single well stage as the optimization goal, optimize the reasonable depressurization mode and depressurization speed of shale oil, and guide the mining of shale oil reservoirs. The present invention provides a scientific and reasonable drainage system to increase the single well production of shale oil reservoirs, mainly by controlling the bottom hole pressure to ensure long-term stable production during the drainage process while reducing the effect of stress sensitivity characteristics, thereby helping to effectively develop shale oil reservoirs.

[0044] Embodiment 1

[0045] Figure 1 This is a step diagram of the method for determining an effective development plan for a shale oil reservoir in an embodiment of the present application. Figure 1 The specific steps and procedures of the method for determining an effective development plan for a shale oil reservoir (also referred to as a "development plan determination method") described in an embodiment of the present invention are described.

[0046] Step S110 is based on the actual formation and development parameters of the area to be studied, establishes a multi-zone coupled seepage mathematical model that characterizes the nonlinear seepage laws of different porous media areas and forms a production calculation model for different fracturing sections of horizontal wells in shale oil reservoirs, thereby establishing a tight oil reservoir production calculation model for the effective utilization range of the reservoir, so as to form a calculation plan for the cumulative production of the reservoir at different development times.

[0047] In one embodiment, the actual formation and development parameters include: porosity of different media regions, matrix permeability, formation thickness, original viscosity, rock compressibility, formation fluid compressibility, original formation pressure, bottom hole pressure under specific conditions, fracture half-length, main fracture width, short axis length of fracture network transformation zone, wellbore radius, horizontal well length and number of volume fracturing segments.

[0048] In step S110, firstly, for each fracturing stage, a corresponding multi-zone coupled seepage mathematical model is established to characterize the nonlinear seepage law of different porous media regions.

[0049] Specifically, artificial main fractures are formed in shale reservoirs after volume fracturing. The large amount of fluid entering the ground causes irregular derivative micro fractures to form near the main fractures. The derivative micro fractures are intertwined with the natural micro fractures in the reservoir, thus forming a complex fracture network. Under the action of formation energy, the formation fluid flows from the matrix area into the fracturing transformation area, then into the main fracture area and finally into the wellbore. For this reason, a three-zone coupled seepage model of the main fracture-fracture network-matrix of the shale reservoir was established, see Figure 3 .

[0050] like Figure 3 As shown in the figure, zone I is the main fracture area formed by volume fracturing, characterized by linear flow inside the fracture (the half-length of the fracture is x f ); Area II is the fracture network area formed by volume fracturing, characterized by an elliptical flow field with the main fracture tip as the focus (the major axis is a n , the minor axis is b n ) to the radial flow of the main fracture area (approximately the line sink), considering the starting pressure gradient G in the fracture network area n ; Zone III is the matrix area that has not been transformed by volume fracturing, similar to the fracturing transformation area, characterized by an elliptical flow field with the main fracture tip as the focus (the long axis is a m , the minor axis is b m ) radial flow to the fracturing zone, considering the starting pressure gradient G of the nano- and micro-pores in the shale reservoir m .

[0051] To this end, it is necessary not only to establish a multi-zone coupled seepage model, but also to establish a mathematical model of the multi-zone coupled seepage model according to the actual strata and development parameters of the area to be studied, that is, a multi-zone coupled seepage mathematical model. In an embodiment of the present invention, the multi-zone coupled seepage mathematical model includes:

[0052] The basic differential equations and boundary conditions of the main fracture region, as well as the pressure and flow model at any point in the main fracture region;

[0053] The basic differential equations and boundary conditions of the fracture network region, the starting pressure gradient model of the fracture network region, and the pressure and flow model at any point in the fracture network region; and

[0054] The basic differential equations and boundary conditions of the matrix region, the starting pressure gradient model of the matrix region, and the pressure and flow model at any point in the matrix region.

[0055] ① Strong transformation area:

[0056] The strong transformation area is the main fracture area formed by hydraulic fracturing, which is characterized by the Darcy seepage process inside the artificial fracture. The basic differential equation and boundary conditions for its stable seepage are established as follows:

[0057]

[0058] Where v represents the seepage function of the strong transformation zone, x represents the position of any point in the strong transformation zone, r represents the radius parameter, p represents the pressure parameter, and k f represents the permeability of the strongly modified zone (in one embodiment, the permeability of the strongly modified zone is 10 -3 μm 2 ), μ represents the formation fluid viscosity, in mPa·s; r w Indicates the wellbore radius, in m; x f represents the half length of the crack, in m; p w Indicates the bottom hole pressure in MPa; p f It indicates the pressure at half the length of the crack in the main crack zone, in MPa.

[0059] The pressure p(x) at any point in the main fracture area is:

[0060]

[0061] The flow rate of the strong transformation area is:

[0062]

[0063] Among them, q f represents the flow rate in the strong transformation area, ω f represents the width of the strongly transformed zone, and h represents the reservoir thickness.

[0064] ②Weakly renovated area:

[0065] The weakly stimulated zone is a fracture network structure formed by volume fracturing, characterized by the elliptical radial flow of the formation fluid in the fracture network toward the main fracture, with the focus being the fracture half-length x f The radial steady-state seepage model is established, and its basic differential equation and boundary conditions are as follows:

[0066]

[0067] In the formula, r n represents the equivalent radius of the outer boundary of the weak transformation zone, in meters; r f represents the equivalent radius of the outer boundary of the strong transformation zone, p n It represents the pressure at the interface between the weakly reformed zone and the matrix zone, in MPa; G n ' represents the starting pressure gradient of the fracture network area in the circular flow field (w plane) of the multi-zone coupled seepage model in the complex potential space, and its action distance is the average minor semi-axis of the ellipse, which is:

[0068]

[0069]

[0070] Where θ represents the angle between any direction and the positive direction of the major axis.

[0071] The pressure p(r) at any point in the seam network area is:

[0072]

[0073] The flow rate in the weak transformation area is:

[0074]

[0075] In the formula, q n represents the flow rate in the weakly transformed area, k n represents the permeability of the weakly modified zone (in one embodiment, the permeability of the weakly modified zone is 10 -3 μm 2 ).

[0076] ③Matrix mobilization area:

[0077] Similarly, when the pressure wave reaches the matrix area, the energy replenishment to the fracture network area is realized, and the basic differential equation and boundary conditions of the mathematical model of stable seepage in the matrix area are:

[0078]

[0079] In the formula, r e represents the equivalent radius at the outer boundary of the matrix mobilization area, in m; p e It indicates the supply pressure from the matrix producing area to the fracture network area, in MPa; G m ' represents the starting pressure gradient of the matrix zone in the circular flow field (w plane) of the multi-zone coupled seepage model in the complex potential space, and is:

[0080]

[0081] In the formula, r m =r e , b m It represents the length of the minor axis of the elliptical flow field after it reaches the matrix area.

[0082] The pressure p(r) at any point in the matrix region is:

[0083]

[0084] The yield in the matrix region is:

[0085]

[0086] In the formula, q m represents the flow rate in the matrix area, k mrepresents the permeability of the matrix mobilization zone (in one embodiment, the permeability of the weakly modified zone is 10 -3 μm 2 ).

[0087] In this way, the construction of the multi-zone coupled seepage model and its mathematical model is completed.

[0088] Then, step S110 of the present invention will also construct a production calculation model for different fracturing stages of horizontal wells in shale oil reservoirs based on the multi-zone coupled seepage mathematical model of each fracturing stage.

[0089] Since the pressure and flow rate at the interface of multiple coupled zones in shale reservoirs are equal, we have:

[0090] ① The pressure at the interface of each zone is equal, that is, the pressure at the outer boundary of the strong transformation zone and the inner boundary of the weak transformation zone is equal, and the pressure at the outer boundary of the weak transformation zone and the inner boundary of the matrix utilization zone is equal, so:

[0091]

[0092]

[0093] Volume fracturing development of shale oil reservoirs meets the flow conservation law, and the pressure at the interface of each zone is conserved. The pressure expression at the interface of different zones can be derived together:

[0094]

[0095]

[0096] In the formula, p Ⅰ 、p Ⅱ and p Ⅲ represent the pressures in the main fracture area, fracture network area, and matrix area, respectively. A, B, and C represent the correlation coefficients, respectively.

[0097] A=k f k n ·ln(r e / r n ) (17)

[0098] B=k f k m ·ln(r n / r f ) (18)

[0099] C=k m k n ·ln(r f / r w ) (19)

[0100] For each fracturing section, the above equations (13) to (19) can be substituted into the multi-zone coupled seepage mathematical model to obtain the radial pressure distribution on the w plane, and mapped to the z plane to obtain the pressure distribution in the elliptical flow field.

[0101] ② The flow rates at the regional interface are equal, that is, the flow rate from the strong transformation area into the wellbore = the flow rate from the weak transformation area into the strong transformation area = the flow rate from the matrix area into the weak transformation area, so:

[0102] q i =q fi =q ni =q mi (20)

[0103] Furthermore, since a corresponding multi-zone coupled seepage mathematical model is established for each fracturing section, for each fracturing section, equation (20) is coupled with the above multi-zone coupled seepage mathematical model, and the solution is obtained jointly, and the interference between multi-stage fractures is considered, the production q of the i-th fracturing section of the horizontal well in the shale oil reservoir can be obtained: i The calculation formula (i.e. the production calculation model for different fracturing stages) is:

[0104]

[0105] In the formula, i represents the serial number of the fracturing stage, q i represents the production of the ith fracturing stage at time t, p ei represents the pressure at the outer boundary of the matrix region of the ith fracturing stage, p wi represents the given bottom hole pressure of the ith fracturing stage, G ni ' represents the starting pressure gradient of the fracture network area in the i-th fracturing stage under the multi-zone coupled seepage model, r ni represents the equivalent radius of the outer boundary of the fracture network area of ​​the i-th fracturing stage, r fi represents the equivalent radius of the outer boundary of the main fracture of the ith fracturing stage, G mi ' represents the starting pressure gradient of the matrix region of the i-th fracturing stage under the multi-zone coupled seepage model, r ei represents the radius of the outer boundary of the matrix region of the i-th fracturing stage, S i represents the area of ​​the overlapped area of ​​adjacent fracture segments of the ith fracturing segment, a i represents the long axis of the elliptical flow field of the multi-zone coupled seepage flow field in the z plane, b i Represents the short axis of the elliptical flow field of the multi-zone coupled seepage flow field in the z plane, R fi represents the equivalent seepage resistance of the main fracture area of ​​the i-th fracturing stage, R ni represents the equivalent seepage resistance of the fracture network area of ​​the i-th fracturing stage, R mirepresents the equivalent seepage resistance of the matrix area of ​​the i-th fracturing stage. i =a i b i ·{2·arccos(d / 2b i )-sin[2·arccos(d / 2b i )]}, d represents the crack segment spacing, the unit is m.

[0106] Among them, the equivalent seepage resistance R of the main fracture area, fracture network area and matrix area of ​​the i-th fracturing stage is f , R n , R m The equivalent seepage resistance corresponding to each area is:

[0107]

[0108]

[0109]

[0110] By adding up the production of multiple fracturing stages, we can get the production of the horizontal wells in the shale oil reservoir under multi-stage fracturing development at the current moment.

[0111] Since the production of tight oil reservoirs decreases rapidly during the development process, based on the multi-region flow field structure mathematical model of reservoir matrix-volume fracturing transformation fracture network-fracture fractures established in the previous article and the production calculation model of different fracturing sections of horizontal wells in shale oil reservoirs, combined with the steady-state seepage characteristics of each time node, and taking into account the characteristics of rapid production decline during constant pressure production in tight oil reservoirs, a calculation scheme for the dynamic swept boundary of volume fracturing development in tight oil reservoirs and the cumulative production of the reservoir is established.

[0112] According to the material balance method, the cumulative output of tight oil reservoirs is equal to the change in pore volume within the effective production range of the reservoir, that is, the calculation model of the cumulative output of tight oil reservoirs is expressed by the following expression:

[0113]

[0114] Where t represents the sequence number of the development time, n represents the total number of current (already) developed time, Q t represents the production at time t (the sum of the production of each fracturing stage at time t), ρ represents the fluid density, φ represents the pore volume at time t, and r w represents the wellbore radius, R t represents the producing radius, h represents the reservoir thickness, and e represents the original state of the formation.

[0115] Furthermore, the cumulative production of oil reservoirs at different development times The calculation scheme includes the following steps:

[0116] In the first step, a multi-zone coupled seepage model of a shale reservoir is constructed according to the above method, and the flow field model parameters of each fracturing section in the area to be studied are determined to form a multi-zone coupled seepage mathematical model of each fracturing section.

[0117] In the second step, according to the actual formation and development parameters of the area to be studied, the multi-zone coupled seepage mathematical model, the production calculation model of different fracturing stages and the cumulative production calculation model of tight oil reservoirs constructed above are used to calculate the production radius R at the first development time t under the circular flow field (w plane) in the complex potential space of the multi-zone coupled seepage model. t and cumulative reservoir production

[0118] The third step is to calculate the flow field model parameters of the multi-zone coupled seepage model in the elliptical flow field (z plane), and based on the calculated flow field model parameters, combined with the cumulative production of the reservoir at the first development moment The average formation pressure of each porous medium region is calculated using the multi-zone coupled seepage mathematical model. It should be noted that the circular flow field during radial flow is easy to solve, but the multi-zone coupled seepage model constructed in the embodiment of the present invention is an elliptical flow field, and it is necessary to use the complex variable function theory to transform the elliptical flow field (z plane) into a circular flow field (w plane) in the complex potential space, so that the equation of the circular flow field can be used to solve it in the complex potential space.

[0119] In the third step, the long axis a of the elliptical flow field of each fracturing section in the z plane of the multi-zone coupled seepage model at time t can be calculated based on the Rokovsky inverse mapping: i and minor axis b i , to use the current calculated flow model parameter a i 、b i To calculate the average formation pressure in each porous medium area.

[0120] Considering the pressure distribution of the start-up pressure gradient, the average formation pressure in each porous medium area is have:

[0121]

[0122] In the formula, r in 、r out Respectively represent the equivalent radius of the inner and outer boundaries of each region, in m; p in 、p out Respectively represent the formation pressure at the inner and outer boundaries of each region, in MPa, and G represents the starting pressure gradient in the fracture network region or matrix region.

[0123] The fourth step is to correct the permeability and starting pressure gradient of each porous medium according to the average formation pressure of each porous medium area and take into account the stress sensitivity, so as to return to the second step to calculate the cumulative production of the reservoir at the second development time according to the corrected permeability and starting pressure gradient of each porous medium, thereby obtaining the producing radius and cumulative production of the reservoir at different development times.

[0124] In the fourth step, the embodiment of the present invention determines the effective stress of each porous medium region according to the average formation pressure of each porous medium region, and then uses the relationship between effective stress and stress sensitivity (see Figure 2 ) to correct the permeability (and starting pressure gradient) of each porous medium.

[0125] In the embodiment of the present invention, the relationship between effective stress and stress sensitivity is constructed using the following method: for the multi-scale flow stress sensitivity of shale reservoirs, the CMS-300 core analysis system is used to test the overburden permeability of shale oil cores in the horizontal well area to be studied. According to the natural energy development model of shale reservoirs, the overburden pressure of the reservoir is simulated by setting the confining pressure, and the back pressure is adjusted to simulate the pore pressure of the reservoir, thereby reflecting the reservoir stress sensitivity characteristics caused by the change of pore fluid pressure. The specific steps are as follows:

[0126] ① Dry the core and evacuate it at -0.1MPa for 5h. Saturate the core with formation water at constant pressure in the core holder. Alternately increase the confining pressure and back pressure to the original formation pressure to avoid drastic changes in the core pore structure.

[0127] ② Inject formation fluid at the inlet at a rate of 0.008 mL / min, and detect the produced fluid at the outlet until the oil content reaches 99.99%. Then temporarily close both the inlet and outlet and let it stand for 12 hours;

[0128] ③ The confining pressure and the inlet flow rate remain unchanged, and the back pressure is gradually reduced to simulate the formation pressure drop caused by the natural energy development process until the pore pressure drops to the lowest bottom hole flow pressure during the production process. After each pressure point is stable for 1.5h to 2.5h, the injection end pressure is recorded, the permeability data under different effective stresses are calculated, and the core permeability is dimensionlessly processed;

[0129] ④ Replace the matrix core, microcrack core and through-fracture core in sequence, and repeat the above process under the same experimental conditions.

[0130] Based on the stress sensitivity characteristic data of the three core media obtained from indoor experiments, and based on the empirical formula of stress sensitivity exponential, the expressions of stress sensitivity coefficient and permeability changing with effective stress were fitted. Comparative analysis found that: with the increase of effective stress, the core permeability decreased significantly, and the decline tended to be gentle; the order of stress sensitivity characteristics from strong to weak is: through-fracture core > micro-fracture core > matrix core. When the effective stress rises to 15MPa, the permeability damage amplitudes of through-fracture core, micro-fracture core and matrix core are 74.7%, 62.8% and 23.7% respectively; the stress sensitivity coefficients are 0.128MPa respectively. -1 (extremely sensitive), 0.0695MPa -1 (strong sensitivity) and 0.01795MPa -1 (Weak sensitivity). In the development of shale reservoirs, fractures are the main contributor to productivity, and the impact of stress sensitivity is more obvious than that of conventional reservoirs and low permeability reservoirs.

[0131] In this way, step S110 described in the embodiment of the present invention can directly obtain the predicted change results of the production (including oil production and water production) of the area to be studied throughout its life cycle based on the actual formation and development parameters of the area to be studied, using the calculation scheme for the cumulative production of the oil reservoir at different development times formed above, see Figure 4 .

[0132] In one embodiment, based on the actual formation and development parameters of a shale oil reservoir in China, the main parameters are: porosity of 0.1, matrix permeability of 0.3mD, formation thickness of 15m, original viscosity of 1.27mPa·s, rock compression coefficient of 7×10 -4 1 / Mpa, formation fluid compression coefficient 4.34×10 -3 1 / Mpa, original formation pressure 15Mpa, bottom hole pressure 5Mpa, fracture half length 200m, main fracture width 7mm, short axis length of fracture network transformation zone 60m, wellbore radius 0.1m, horizontal well length 2000m, number of fracturing stages 12. Simulate shale oil depletion development for 4000 days and predict cumulative oil production and cumulative water production. Figure 4 Therefore, according to the dynamic supply boundary spreading to different regions, the shale oil development process can be divided into three stages: high-speed nonlinear flow, quasi-linear seepage and low-speed non-Darcy seepage.

[0133] After forming the above-mentioned full life cycle production prediction plan, enter step S120.

[0134] By comparing the technical solutions of the depressurization mining method widely used in the prior art to effectively improve the recovery of shale oil, step S120 of the present invention can control the bottom hole pressure and stepwise reduce the bottom hole pressure. By optimizing the pressure control cycle and the pressure reduction rate, an effective development method of "increasing oil and reducing water" that suppresses the stress sensitivity characteristics of shale oil reservoirs and increases the imbibition replacement effect is selected. The comparison results are as follows: Figure 5 shown.

[0135] Step S120 uses the calculation scheme of the cumulative production of the oil reservoir at different development moments formed in step S110 to determine the best development scheme.

[0136] In step S120, first, the optimal pressure control period is determined according to the cumulative production of the reservoir at different development times.

[0137] Specifically, in the process of determining the optimal pressure control cycle, firstly, by giving the bottom hole pressure sequence under different pressure control cycles and using the calculation scheme of the cumulative production of the reservoir at different development times, the cumulative production of the reservoir under each pressure control cycle is calculated respectively.

[0138] In the embodiment of the present invention, the amplitude of each pressure element in the bottom hole pressure sequence is reduced in a step-by-step manner according to the preset number of elements per interval. For example, the bottom hole pressures are given as A, B, C, D and E for different development time periods of 1-500 days, 501-1000 days, 1001-1500 days, 1501-2000 days and 2001-2500 days, respectively, and the amplitude of the current pressure sequence element decreases in a step-by-step manner. Therefore, the production prediction scheme formed in step S110 is used to calculate the cumulative production of the reservoir in different development time periods, as shown in Table 1.

[0139] Table 1 is the cumulative output statistics of different pressure control cycles

[0140]

[0141]

[0142] A comparative analysis of the cumulative oil and water production of the schemes with pressure control times of 500 days, 1000 days, 1500 days, 2000 days and 2500 days (Table 1) shows that there is an optimal pressure control time for shale oil depressurization, and the recovery degree is highest in the quasi-linear flow stage.

[0143] Then, the pressure control period corresponding to the maximum value of the cumulative production of the reservoir is taken as the optimal pressure control period.

[0144] When the pressure spreads to the matrix area, shale oil production reaches the low-speed non-Darcy seepage stage, and its dynamic attack boundary spreads to the matrix area, and the production speed is significantly reduced. Affected by the weak stress sensitivity of the matrix area, the effect of increasing the production pressure difference is slow. Therefore, the implementation of pressure control production in the quasi-linear flow stage effectively suppresses the stress sensitivity in the fracturing transformation volume. The 1000-day pressure control scheme can increase oil production by 1168 tons and reduce water by 3134 tons (4000 days of production) compared with conventional pressure release production, which improves the effective use of shale oil reservoirs. Therefore, the optimal pressure control period in Table 1 is determined to be 1000 days.

[0145] Next, step S120 determines the optimal pressure control mode by respectively calculating the cumulative production of the reservoir under different pressure control modes under the optimal pressure control period.

[0146] After determining the optimal voltage control period, the present invention will also optimize the optimal voltage control mode.

[0147] Specifically, firstly, the present invention will give a bottom hole pressure sequence under different pressure control modes, and use the calculation scheme of the cumulative production of the reservoir at different development times to calculate the cumulative production of the reservoir under each pressure control mode.

[0148] In the embodiment of the present invention, the configured different pressure control modes include: constant speed pressure reduction, first fast then slow (pressure reduction frequency first fast then slow) and first slow then fast (pressure reduction frequency first slow then fast). Specifically, the amplitude of each pressure element in the bottom hole pressure sequence is reduced according to a different number of elements per interval.

[0149] In one embodiment, the bottom hole pressure variation curves of the three pressure control modes, namely, constant speed pressure reduction, first fast then slow, and first slow then fast, are as follows: Figure 6 As shown, for each pressure control mode, a corresponding bottom hole pressure sequence is formed as a given value (the actual formation and development parameters of the area to be studied). Then, using the production change prediction scheme formed in step S110, the cumulative oil production and cumulative water production of the three pressure control modes over the entire life cycle are calculated respectively, so as to compare and analyze the cumulative oil production and water production under the three pressure control modes, as shown in FIG. Figure 7 Among them, the cumulative oil production and cumulative water production of different pressure control modes under the optimal pressure control cycle are shown in Table 2.

[0150] Table 2 Cumulative production statistics of different pressure control modes under the optimal pressure control cycle

[0151]

[0152]

[0153] Finally, the pressure control mode corresponding to the maximum value of the cumulative production of the reservoirs in different modes under the optimal pressure control cycle is taken as the optimal pressure control mode.

[0154] As can be seen from Table 2, the cumulative production of shale oil using the pressure reduction speed mode of first fast and then slow is the highest. This development mode is of great significance to improving the recovery of shale oil.

[0155] In this way, after optimizing the best pressure control cycle and the best pressure control mode, the effective development plan for horizontal wells in the shale oil reservoir to be studied is determined.

[0156] Embodiment 2

[0157] Based on the development plan determination method formed in the above-mentioned embodiment 1, the embodiment of the present invention also provides a computer-readable storage medium, on which a computer program is stored, and the computer program is executed to run a method for analyzing the main control factors of high production for deep oil reservoir wells. The computer program can run computer instructions, and the computer instructions include computer program codes, and the computer program codes can be in source code form, object code form, executable file or some intermediate form, etc.

[0158] Computer-readable storage media may include: any entity or device that can carry computer program code, recording media, USB flash drives, mobile hard disks, magnetic disks, optical disks, computer memory, read-only memory (ROM), random access memory (RAM), electrical carrier signals, telecommunication signals, and software distribution media, etc.

[0159] It should be noted that the content contained in computer-readable storage media can be appropriately increased or decreased according to the requirements of legislation and patent practice in the jurisdiction. For example, in some jurisdictions, the content contained in computer-readable storage media does not include electrical carrier signals and telecommunication signals.

[0160] Embodiment 3

[0161] Based on the development plan determination method formed in the above-mentioned embodiment 1, the embodiment of the present invention also provides a system for determining an effective development plan for a shale oil reservoir (also referred to as a "development plan determination system"). Figure 8 This is a schematic diagram of the structure of a system for determining an effective development plan for a shale oil reservoir according to an embodiment of the present application.

[0162] like Figure 8 As shown, the development plan determination system described in the embodiment of the present invention includes: a cumulative output calculation plan forming module 810 and a development plan forming module 820.

[0163] Specifically, the cumulative production calculation plan forming module 810 is implemented according to the method described in the above step S110, and is configured to establish a multi-zone coupled seepage mathematical model that characterizes the nonlinear seepage laws of different porous media regions based on the actual formation and development parameters of the area to be studied, and form a production calculation model for different fracturing sections of horizontal wells in shale oil reservoirs, thereby establishing a tight oil reservoir production calculation model for the effective utilization range of the reservoir to form a calculation plan for the cumulative production of the reservoir at different development times; the development plan forming module 820 is implemented according to the method described in the above step S120, and is configured to use the calculation plan for the cumulative production of the reservoir at different development times to determine the best development plan.

[0164] The present invention discloses a method and system for determining an effective development plan for shale oil reservoirs, which belongs to the technical field of unconventional oil and gas field development, and particularly relates to an effective development method for controlling bottom hole pressure in shale oil reservoirs. Specifically, for the multi-scale flow medium formed by volume fracturing of shale oil reservoirs, firstly, through indoor core displacement experiments, the stress sensitivity characteristics of shale matrix cores and semi-filled / fully-filled fracture cores are revealed (semi-filled / fully-filled fracture cores correspond to artificial fractures and micro-fractures, respectively), and a characterization formula for the equivalent permeability of shale oil in different porous media is established; secondly, according to the seepage characteristics of different porous media, a multi-zone coupled seepage mathematical model characterizing matrix-micro-fractures-artificial fractures is established; thirdly, through multi-zone coupling solution, a non-steady-state production prediction method for shale oil reservoirs is derived, and the law of full life cycle production decline is clarified; finally, through the analysis of influencing factors, a step-by-step pressure reduction mining method is proposed, and the pressure reduction speed and pressure reduction cycle are optimized. The present invention can economically and effectively improve the recovery degree of shale oil volume fracturing development on the basis of the existing pressure release mining method.

[0165] Specifically, the present invention effectively suppresses the damage of strong stress sensitivity to shale oil reservoirs during the development process by controlling the bottom hole pressure in the exploitation stage, and increases the imbibition displacement effect, showing the development effect of "increasing oil and reducing water", and achieving an increase in the degree of recovery. In addition, the present invention optimizes the pressure control time and pressure control mode, and can increase the degree of recovery by 3.74% compared with the pressure release production and development mode. In this way, the present invention targets the multi-scale seepage characteristics of shale oil reservoirs after volume fracturing, and improves the degree of recovery of shale oil by adjusting the pressure reduction rate under existing development process conditions. It is low-cost, effective and practical, and has strong operability, and can guide the effective development of shale oil.

[0166] The above is only a preferred specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Any changes or substitutions that can be easily thought of by any person familiar with the technology within the technical scope disclosed by the present invention should be included in the protection scope of the present invention. Therefore, the protection scope of the present invention should be based on the protection scope of the claims.

[0167] In the description of the present invention, unless otherwise specified, "plurality" means two or more than two; the orientations or positional relationships indicated by the terms "upper", "lower", "left", "right", "inner", "outer", "front end", "rear end", "head", "tail", etc. are based on the orientations or positional relationships shown in the drawings, and are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operate in a specific orientation, and therefore cannot be understood as limiting the present invention. In addition, the terms "first", "second", "third", etc. are only used for descriptive purposes and cannot be understood as indicating or implying relative importance.

[0168] In the description of the present invention, it should be noted that, unless otherwise clearly specified and limited, the terms "connected" and "connection" should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be a direct connection or an indirect connection through an intermediate medium. For ordinary technicians in this field, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0169] It should be understood that the embodiments disclosed in the present invention are not limited to the specific structures, processing steps or materials disclosed herein, but should be extended to equivalent substitutions of these features understood by ordinary technicians in the relevant field. It should also be understood that the terms used herein are only used for the purpose of describing specific embodiments and are not meant to be limiting.

[0170] The "one embodiment" or "embodiment" mentioned in the specification means that the specific features, structures or characteristics described in conjunction with the embodiment are included in at least one embodiment of the present invention. Therefore, the phrases "one embodiment" or "embodiment" appearing in various places throughout the specification do not necessarily refer to the same embodiment.

[0171] Although the embodiments disclosed in the present invention are as above, the contents described are only embodiments adopted for facilitating the understanding of the present invention and are not intended to limit the present invention. Any technician in the technical field to which the present invention belongs can make any modifications and changes in the form and details of the implementation without departing from the spirit and scope disclosed in the present invention, but the patent protection scope of the present invention shall still be subject to the scope defined in the attached claims.

Claims

1. A method for determining an effective development plan for a shale oil reservoir, characterized in that: include: Based on the actual formation and development parameters of the area to be studied, a multi-zone coupled seepage mathematical model is established to characterize the nonlinear seepage laws of different porous media areas and to form a production calculation model for different fracturing stages of horizontal wells in shale oil reservoirs, thereby establishing a tight oil reservoir production calculation model for the effective production range of the reservoir to form a calculation plan for the cumulative production of the reservoir at different development times; The optimal development plan is determined by using the calculation plan of the cumulative production of the oil reservoir at different development times.

2. The method according to claim 1, characterized in that The calculation scheme of the cumulative production of oil reservoirs at different development times includes the following steps: The first step is to establish a multi-zone coupled seepage model for shale reservoirs and determine the flow field model parameters in the area to be studied; The second step is to calculate the producing radius and the cumulative production of the reservoir at the first development moment under the multi-zone coupled seepage model by using the multi-zone coupled seepage mathematical model, the production calculation model of different fracturing stages and the cumulative production calculation model of the tight oil reservoir according to the actual formation and development parameters of the area to be studied; The third step is to calculate the flow field model parameters of the multi-zone coupled seepage model under the elliptical flow field, based on which, combined with the cumulative production of the oil reservoir at the first development moment, the multi-zone coupled seepage mathematical model is used to calculate the average formation pressure of each porous medium area; The fourth step is to correct the permeability and starting pressure gradient of each porous medium according to the average formation pressure of each porous medium area and take stress sensitivity into consideration, so as to return to the second step to calculate the cumulative production of the reservoir at the second development time according to the corrected permeability of each porous medium, and then obtain the producing radius and cumulative production of the reservoir at the different development times.

3. The method according to claim 2, characterized in that The tight oil reservoir production calculation model is expressed by the following expression: Among them, t represents the development time, n represents the total number of development time, Q t represents the production at time t, ρ represents the fluid density, φ represents the pore volume at time t, and r w represents the wellbore radius, R t represents the producing radius, r represents the radius, h represents the reservoir thickness, and e represents the original state of the formation, wherein the production calculation model of different fracturing stages is expressed by the following expression: Where i represents the serial number of the fracturing stage, q i represents the production of the ith fracturing stage at time t, p ei represents the pressure at the outer boundary of the matrix region of the ith fracturing stage, p wi represents the given bottom hole pressure of the ith fracturing stage, G ni ' represents the starting pressure gradient of the fracture network area in the i-th fracturing stage under the multi-zone coupled seepage model, r ni represents the equivalent radius of the outer boundary of the fracture network area of ​​the i-th fracturing stage, r fi represents the equivalent radius of the outer boundary of the main fracture of the ith fracturing stage, G mi ' represents the starting pressure gradient of the matrix region of the i-th fracturing stage under the multi-zone coupled seepage model, r ei represents the radius of the outer boundary of the matrix region of the i-th fracturing stage, S i represents the area of ​​the overlapped area of ​​adjacent fracture segments of the ith fracturing segment, a i represents the long axis of the elliptical flow field of the multi-zone coupled seepage flow field in the z plane, b i Represents the short axis of the elliptical flow field of the multi-zone coupled seepage flow field in the z plane, R fi represents the equivalent seepage resistance of the main fracture area of ​​the i-th fracturing stage, R ni represents the equivalent seepage resistance of the fracture network area of ​​the i-th fracturing stage, R mi represents the equivalent seepage resistance of the matrix region of the i-th fracturing stage.

4. The method according to any one of claims 1 to 3, characterized in that The multi-zone coupled seepage mathematical model includes: Basic differential equations and boundary conditions of the main fracture region, and pressure and flow models at any point in the main fracture region; Basic differential equations and boundary conditions of the fracture network region, a starting pressure gradient model, and a pressure and flow model for any point in the fracture network region; and The basic differential equations and boundary conditions of the matrix region, the starting pressure gradient model, and the pressure and flow model at any point in the matrix region.

5. The method according to any one of claims 1 to 4, characterized in that: The step of determining the best development plan by using the calculation scheme of the cumulative production of the oil reservoir at different development moments includes: Determining the optimal pressure control period according to the cumulative production of the oil reservoir at different development times; The optimal pressure control mode is determined by respectively calculating the cumulative production of the reservoir under different pressure control modes under the optimal pressure control period.

6. The method according to claim 5, characterized in that The step of determining the optimal pressure control period according to the cumulative production of the oil reservoir at different development times includes: Given a bottom hole pressure sequence under different pressure control cycles, the cumulative production of the reservoir under each pressure control cycle is calculated using the calculation scheme of the cumulative production of the reservoir under different development moments, and the amplitude of each pressure element in the bottom hole pressure sequence is reduced in a stepwise manner according to a preset number of elements per interval; The pressure control period corresponding to the maximum value of the cumulative production of the oil reservoir is taken as the optimal pressure control period.

7. The method according to claim 5 or 6, characterized in that: The step of determining the optimal pressure control mode by respectively calculating the cumulative production of the reservoir under different pressure control modes under the optimal pressure control period includes: Given a bottom hole pressure sequence under different pressure control modes, using the calculation scheme of the cumulative production of the reservoir at different development times, the cumulative production of the reservoir under each pressure control mode is calculated respectively, the different pressure control modes include constant speed pressure reduction, first fast then slow, and first slow then fast, and the amplitude of each pressure element in the bottom hole pressure sequence is reduced according to a different number of elements per interval; The pressure control mode corresponding to the maximum value of the accumulated production of the oil reservoir is taken as the optimal pressure control mode.

8. The method according to any one of claims 1 to 7, characterized in that: The actual formation and development parameters include: porosity of different media areas, matrix permeability, formation thickness, original viscosity, rock compressibility, formation fluid compressibility, original formation pressure, bottom hole pressure under specific conditions, fracture half-length, main fracture width, short axis length of fracture network transformation zone, wellbore radius, horizontal well length and number of volume fracturing sections.

9. A computer-readable storage medium, characterized in that: It contains a series of instructions for executing the method steps as claimed in any one of claims 1 to 8.

10. A system for determining an effective development plan for a shale oil reservoir, characterized in that: include: The cumulative production calculation scheme forming module is configured to establish a multi-zone coupled seepage mathematical model that characterizes the nonlinear seepage law of different porous media regions based on the actual formation and development parameters of the area to be studied, and to form a production calculation model for different fracturing stages of horizontal wells in shale oil reservoirs, thereby establishing a tight oil reservoir production calculation model for the effective production range of the reservoir, so as to form a calculation scheme for the cumulative production of the reservoir at different development times; The development plan forming module is configured to determine the best development plan using the calculation plan of the cumulative production of the oil reservoir at different development moments.

Images