Method and device for predicting carbon dioxide huff and puff effect of shale oil reservoir

Abstract

The application discloses a shale oil reservoir carbon dioxide huff and puff effect prediction method and device. Wherein, the method comprises: obtaining the unit fracture area oil increment of the shale oil reservoir, wherein the unit fracture area oil increment dynamically changes with the diffusion depth of the carbon dioxide gas in the fracture of the shale oil reservoir, and the carbon dioxide gas is injected into the shale oil reservoir in advance; determining the target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes with the cumulative open well time of the shale oil reservoir; based on the target fracture area and the unit fracture area oil increment, determining the oil increment evaluation result of the shale oil reservoir. The application solves the technical problems of large calculation amount, long time consumption, large fracture characterization difficulty and inaccurate evaluation in the related art, because the shale oil reservoir carbon dioxide huff and puff effect is mainly determined by the conventional reservoir numerical simulation method.

Description

Technical Field

[0001] This invention relates to the field of shale oil reservoir development technology, and more specifically, to a method and apparatus for predicting the carbon dioxide huff and puff effect of shale oil reservoirs. Background Technology

[0002] Shale oil, as an unconventional oil and gas resource, has been widely used. However, due to its low reservoir permeability, it is difficult to establish an effective displacement pressure system with water injection under economically limited well patterns. Currently, the "horizontal well + volumetric fracturing" method is commonly used to achieve efficient shale oil development. Molecular diffusion during carbon dioxide huff and puff is an important mechanism for enhancing shale oil recovery. Optimizing the carbon dioxide huff and puff injection volume by considering molecular diffusion is a key factor affecting the effectiveness and efficiency of shale oil huff and puff. Insufficient injection volume results in poor oil recovery, while excessive volume leads to ineffective gas injection cycles, impacting overall efficiency.

[0003] Current shale oil injection parameter optimization design methods, following conventional reservoir approaches, use reservoir numerical simulation software to predict oil increase through geological modeling and reservoir numerical simulation. This primarily relies on adjusting hydrocarbon phase permeability during gas injection, resulting in a relatively simplistic approach. Furthermore, reservoir numerical simulation suffers from numerous drawbacks, including the difficulty in establishing fracture models, particularly for unconventional reservoirs with large-scale volumetric fracturing, leading to poor fracture characterization accuracy, requiring extensive baseline data, being time-consuming, and being influenced by numerous factors.

[0004] There is currently no effective solution to the above problems. Summary of the Invention

[0005] This invention provides a method and apparatus for predicting the carbon dioxide huff and puff effect in shale oil reservoirs, which at least solves the technical problems of large computational load, long time consumption, difficulty in fracture characterization, and inaccurate evaluation in related technologies, which mainly rely on conventional reservoir numerical simulation methods to determine the carbon dioxide huff and puff effect in shale oil reservoirs.

[0006] According to one aspect of the present invention, a method for predicting the carbon dioxide huff and puff effect of a shale oil reservoir is provided, comprising: obtaining the oil increase per unit fracture area of ​​the shale oil reservoir, wherein the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining the target fracture area of ​​the shale oil reservoir, wherein the target fracture area is dynamically varied with the cumulative well operating time of the shale oil reservoir; determining the oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area; and determining the carbon dioxide huff and puff effect of the shale oil reservoir based on the oil increase assessment result.

[0007] Optionally, determining the target fracture area of ​​the shale oil reservoir includes: obtaining historical production data of the shale oil reservoir, wherein the historical production data includes at least: crude oil production, water cut, formation pressure and bottom hole flow pressure corresponding to the shale oil reservoir; and determining the target fracture area based on the historical production data.

[0008] Optionally, determining the target crack area based on the aforementioned production history data includes: calculating multiple crack areas at different historical moments based on the aforementioned production history data; selecting the crack area corresponding to the moisture content being within a first preset range from the multiple crack areas; determining the average value of the crack areas corresponding to the moisture content being within the first preset range, and using the average value as the target crack area.

[0009] Optionally, based on the aforementioned historical production data, multiple fracture areas at different historical moments are obtained, including: acquiring the reservoir physical properties, high-pressure crude oil physical properties, and cumulative well operating time corresponding to the aforementioned shale oil reservoir. The reservoir physical properties include at least: crude oil saturation pressure, crude oil compressibility, formation volume coefficient, and formation crude oil viscosity; and the reservoir physical properties include at least: matrix overburden permeability, matrix overburden porosity, and bound water saturation. Based on the aforementioned historical production data, the aforementioned reservoir physical properties, high-pressure crude oil physical properties, and the aforementioned cumulative well operating time, multiple fracture areas at different historical moments are obtained in the following manner: Among them, A f1 q represents the crack area at different historical moments. o B represents the above crude oil production. o P represents the above-mentioned formation volume factor. i P represents the aforementioned formation pressure. wf The above-mentioned bottom hole flow pressure, μ o The viscosity of the crude oil in the above formation is expressed in t. k The above represents the cumulative well opening time, K represents the above matrix overburden permeability, φ represents the above matrix overburden porosity, and C represents the above matrix overburden porosity. t The comprehensive compression coefficient is defined based on the crude oil compression coefficient and the bound water saturation.

[0010] Optionally, the above-mentioned determination of the oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area includes: obtaining the surface crude oil density corresponding to the shale oil reservoir, and the target diffusion distance of carbon dioxide gas in the fractures of the shale oil reservoir, wherein the target diffusion distance is the distance between the position where the carbon dioxide gas concentration in the fractures of the shale oil reservoir reaches a preset concentration and the fracture surface of the shale oil reservoir after the carbon dioxide gas is injected into the shale oil reservoir and the shale oil reservoir is subjected to well shut-in treatment; determining the oil increase assessment result of the shale oil reservoir based on the surface crude oil density, the target diffusion distance, the target fracture area, and the oil increase per unit fracture area; and determining the carbon dioxide huff and puff effect of the shale oil reservoir based on the oil increase assessment result.

[0011] Optionally, based on the aforementioned surface crude oil density, the aforementioned target diffusion distance, the aforementioned target fracture area, and the aforementioned increase in oil volume per unit fracture area, the oil increase assessment result for the aforementioned shale oil reservoir is determined: Among them, A f For the target crack area mentioned above, ρ o Let d be the density of the crude oil on the ground, d be the diffusion distance of the target, and q be the density of the crude oil on the ground. o (x) represents the amount of oil added per unit crack area.

[0012] Optionally, the above method further includes: obtaining the above-mentioned surface crude oil density, diffusion depth, matrix overburden porosity, matrix bound water saturation, crude oil volume factor, and crude oil volume expansion factor corresponding to the above-mentioned shale oil reservoir, wherein the above-mentioned crude oil volume expansion factor is the expansion factor of the crude oil volume in the above-mentioned shale oil reservoir compared to before the injection of the above-mentioned carbon dioxide gas after the above-mentioned carbon dioxide gas is injected into the above-mentioned shale oil reservoir and the well is shut off, and the above-mentioned crude oil volume expansion factor dynamically changes with the diffusion depth of the carbon dioxide gas in the fractures of the above-mentioned shale oil reservoir; and determining the above-mentioned increase in oil volume per unit fracture area based on the above-mentioned surface crude oil density, diffusion depth, matrix overburden porosity, matrix bound water saturation, crude oil volume factor, and crude oil volume expansion factor.

[0013] Optionally, based on the above-mentioned surface crude oil density, diffusion depth, matrix overburden porosity, matrix bound water saturation, crude oil volume coefficient, and crude oil volume expansion factor, the above-mentioned increase in oil volume per unit fracture area is determined as follows: Where, q o (x) represents the oil increase per unit crack area, ρ o The above-mentioned surface crude oil density is represented by x, the above-mentioned diffusion depth is represented by φ, and the above-mentioned matrix overburden porosity is represented by S. wiB represents the bound water saturation of the above-mentioned matrix. o V represents the above crude oil volume coefficient. s (x) represents the volume expansion factor of the crude oil mentioned above.

[0014] According to another aspect of the present invention, a device for predicting the carbon dioxide huff and puff effect of a shale oil reservoir is also provided, comprising: an acquisition module for acquiring the oil increase per unit fracture area of ​​the shale oil reservoir, wherein the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; a first determination module for determining the target fracture area of ​​the shale oil reservoir, wherein the target fracture area is dynamically varied with the cumulative well operating time of the shale oil reservoir; a second determination module for determining an oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area; and determining the carbon dioxide huff and puff effect of the shale oil reservoir based on the oil increase assessment result.

[0015] According to another aspect of the present invention, a non-volatile storage medium is also provided, which stores a plurality of instructions adapted for a processor to load and execute any one of the above-described methods for predicting the carbon dioxide throughput effect of shale oil reservoirs.

[0016] In this embodiment of the invention, the oil increase per unit fracture area of ​​a shale reservoir is obtained, wherein the oil increase per unit fracture area is dynamically changed with the diffusion depth of carbon dioxide gas in the fractures of the shale reservoir, and the carbon dioxide gas is pre-injected into the shale reservoir; a target fracture area of ​​the shale reservoir is determined, wherein the target fracture area is dynamically changed with the cumulative well opening time of the shale reservoir; based on the target fracture area and the oil increase per unit fracture area, the oil increase assessment result of the shale reservoir is determined; according to the oil increase assessment result, the carbon dioxide huff and puff effect of the shale reservoir is determined, achieving the goal of comprehensively considering gas diffusion and dynamic changes in fracture area to determine the carbon dioxide huff and puff effect of the shale reservoir, thereby achieving the technical effect of improving the prediction efficiency and accuracy of the carbon dioxide huff and puff effect of shale reservoirs, and thus solving the technical problems of large computational load, long time consumption, difficulty in fracture characterization, and inaccurate assessment that exist in related technologies where the carbon dioxide huff and puff effect of shale reservoirs is mainly determined by conventional reservoir numerical simulation methods. Attached Figure Description

[0017] The accompanying drawings, which are included to provide a further understanding of the invention and form part of this application, illustrate exemplary embodiments of the invention and, together with their description, serve to explain the invention and do not constitute an undue limitation thereof. In the drawings:

[0018] Figure 1 This is a flowchart of a method for predicting the carbon dioxide huff and puff effect in shale oil reservoirs according to an embodiment of the present invention;

[0019] Figure 2a This is a schematic diagram illustrating the relationship between diffusion depth and carbon dioxide gas concentration under different optional well-clogging times according to an embodiment of the present invention.

[0020] Figure 2b This is a schematic diagram illustrating the correspondence between an optional target diffusion distance and well-clogging time according to an embodiment of the present invention;

[0021] Figure 3 This is a schematic diagram illustrating the relationship between an optional crude oil volume expansion factor and the concentration of carbon dioxide gas according to an embodiment of the present invention.

[0022] Figure 4 This is a schematic diagram of a shale oil reservoir carbon dioxide huff and puff effect prediction device according to an embodiment of the present invention;

[0023] Figure 5 This is a schematic diagram of the structure of an electronic device according to an embodiment of the present invention. Detailed Implementation

[0024] To enable those skilled in the art to better understand the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of the present invention.

[0025] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this invention are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of the invention described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0026] According to an embodiment of the present invention, a method for predicting the carbon dioxide huff and puff effect of shale oil reservoirs is provided. It should be noted that the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions. Furthermore, although a logical order is shown in the flowchart, in some cases, the steps shown or described may be executed in a different order than that shown here.

[0027] Figure 1 This is a flowchart of a method for predicting the carbon dioxide huff and puff effect in shale oil reservoirs according to an embodiment of the present invention, such as... Figure 1 As shown, the method includes the following steps:

[0028] Step S102: Obtain the oil increase per unit fracture area in shale oil reservoirs;

[0029] Step S104: Determine the target fracture area of ​​the aforementioned shale oil reservoir;

[0030] Step S106: Based on the target fracture area and the oil increase per unit fracture area, determine the oil increase assessment result of the shale oil reservoir; based on the oil increase assessment result, determine the carbon dioxide huff and puff effect of the shale oil reservoir.

[0031] Through the above steps, the goal of determining the carbon dioxide huff and puff effect of shale oil reservoirs can be achieved by comprehensively considering factors such as gas diffusion and dynamic changes in fracture area. This improves the efficiency and accuracy of predicting the carbon dioxide huff and puff effect of shale oil reservoirs, and solves the technical problems of large computational load, long time consumption, difficulty in fracture characterization, and inaccurate evaluation that exist in related technologies where the carbon dioxide huff and puff effect of shale oil reservoirs is mainly determined by conventional reservoir numerical simulation methods.

[0032] Optionally, the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; the target fracture area is dynamically varied with the cumulative well operating time of the shale oil reservoir.

[0033] It should be noted that related technologies mainly utilize reservoir numerical simulation software to optimize gas injection volume through geological modeling and reservoir numerical simulation. The prediction of the huff and puff effect is primarily achieved by adjusting the oil-gas phase permeability during the gas injection process, without considering the contribution of molecular diffusion mechanisms caused by pore size effects in unconventional reservoirs to improved oil recovery. Furthermore, the accuracy of reservoir numerical simulation prediction methods largely depends on the accuracy of the fracture model; however, characterizing fractures at the scale of volumetric fracturing in unconventional reservoirs is difficult and lacks accuracy. The shale reservoir carbon dioxide huff and puff effect prediction method of this invention, while determining the shale reservoir carbon dioxide huff and puff effect based on the shale reservoir's oil gain, simultaneously considers gas diffusion and dynamic changes in fracture area. Specifically, it determines the oil gain per unit fracture area based on the gas diffusion principle and obtains the dynamic fracture area based on the cumulative well operating time of the shale reservoir. The resulting shale reservoir oil gain is higher and closer to reality, thus improving the accuracy of the predicted shale reservoir carbon dioxide huff and puff effect.

[0034] In an optional embodiment, determining the target fracture area of ​​the shale reservoir includes:

[0035] Obtain the production history data of the aforementioned shale oil reservoirs, wherein the aforementioned production history data shall include at least: the crude oil production, water cut, formation pressure and bottom hole flow pressure corresponding to the aforementioned shale oil reservoirs;

[0036] Based on the aforementioned historical production data, the target crack area was determined.

[0037] Optionally, when determining the target fracture area, factors such as crude oil production, water cut, formation pressure, and bottom hole flow pressure corresponding to the shale reservoir, as well as their dynamic changes over time, are also considered. This makes the obtained fracture area of ​​the shale reservoir (i.e., the target fracture area) more realistic, better meets the needs of shale reservoir gas injection calculation, and makes the obtained shale reservoir gas injection accuracy higher, thereby making the obtained shale reservoir carbon dioxide huff and puff effect prediction better.

[0038] In an optional embodiment, determining the target crack area based on the aforementioned production history data includes:

[0039] Based on the above production history data, the areas of multiple cracks at different historical moments were calculated;

[0040] Select the crack area whose moisture content falls within the first preset range from the above multiple crack areas;

[0041] The average value of the crack area corresponding to the moisture content being within the first preset range is determined, and the average value is taken as the target crack area.

[0042] Optionally, based on historical production data of shale oil reservoirs, crude oil production, water cut, formation pressure, and bottom hole flowing pressure at different historical moments are collected, along with the corresponding reservoir physical properties, crude oil high-pressure physical properties, and cumulative well operation time. Based on the aforementioned crude oil production, water cut, formation pressure, bottom hole flowing pressure, and the corresponding reservoir physical properties, crude oil high-pressure physical properties, and cumulative well operation time, multiple fracture areas at different historical moments are determined. The fracture areas corresponding to water cut within a first preset range (e.g., 15%) are then selected. If there are multiple fracture areas corresponding to water cut within the first preset range (e.g., less than 15%), the average value of these multiple fracture areas that meet the water cut requirement is calculated as the target fracture area.

[0043] Optionally, the aforementioned water cut is determined based on the water cut variation curve collected in the shale reservoir field. For example, the first preset range for water cut variation is selected as water cut less than 15% based on the water cut variation curve. Furthermore, since the flow fracture area (i.e., the aforementioned target fracture area) changes over time, primarily influenced by factors such as production pressure differential, shale reservoir production, reservoir properties, and fluid properties, it is recommended that the calculated value be selected after the fracturing fluid flowback is completed and the water cut drops below 15%.

[0044] In one optional embodiment, the above-mentioned production history data is used to obtain multiple crack areas at different historical moments, including:

[0045] Obtain the reservoir physical property parameters, crude oil high pressure physical property parameters, and cumulative well opening time corresponding to the above-mentioned shale oil reservoir. Among them, the above-mentioned reservoir physical property parameters include at least: crude oil saturation pressure, crude oil compressibility, formation volume factor, and formation crude oil viscosity. The above-mentioned reservoir physical property parameters include at least: matrix overburden permeability, matrix overburden porosity, and bound water saturation.

[0046] Based on the above production history data, reservoir properties, high-pressure crude oil properties, and cumulative well operating time, the fracture areas at different historical moments were obtained as follows:

[0047]

[0048] Among them, A f1 This represents the crack area at different historical moments, in meters (m²). 2 ;q o The above crude oil production is expressed in m³. 3 / d (cubic meters per minute); B o The above-mentioned formation volume factor is expressed in decimal form; P i The above-mentioned formation pressure is expressed in MPa (megapascals); Pwf The above represents the bottom hole flow pressure, in MPa; μ o The viscosity of the crude oil in the above formation is expressed in centipoise (Cp); t k The above represents the cumulative well opening time, in days (minutes); K represents the above matrix overburden permeability, in millidarcy (mD); φ represents the above matrix overburden porosity, in percent; C t The comprehensive compression coefficient is expressed in mD (millidarcy); the comprehensive compression coefficient is determined based on the crude oil compression coefficient and the bound water saturation, and the crude oil production can be the daily crude oil production.

[0049] Optionally, the above-mentioned comprehensive compression coefficient C can be obtained in the following way. t :

[0050]

[0051] Among them, C o C represents the compressibility coefficient of crude oil, with units of 1 / MPa; w C represents the formation water compressibility coefficient, with units of 1 / MPa; f S represents the compressibility of the rock pore system, with units of 1 / MPa; wi It represents the saturation of bound water in the matrix and can be in decimal form.

[0052] Optionally, during the actual exploitation of shale oil reservoirs, it is necessary to monitor various parameters in real time and generate corresponding test reports. Most of the parameters involved in this embodiment of the invention can be obtained from the generated test reports. For example, but not limited to, the aforementioned high-pressure physical properties of crude oil, such as crude oil saturation pressure (p), can be obtained from pre-collected crude oil constant-mass expansion test reports. b ), volume index (B) o ), crude oil compressibility coefficient (C o Viscosity (μ) o Parameters such as volume index and compressibility coefficient are affected by formation pressure; these reservoir physical parameters can be obtained, but are not limited to, from pre-collected shale reservoir core test and analysis reports, such as overburden porosity (φ) and permeability (K) and bound water saturation (S) under reservoir matrix conditions. wc ).

[0053] Optionally, pressure measurement data of the shale oil reservoir are collected before it is put into production to obtain the original formation pressure (p) of the shale oil reservoir. i ).

[0054] Optionally, but not limited to, the rock pore compressibility coefficient corresponding to the shale oil reservoir can be tested according to the standard "Method for Determination of Rock Pore Volume Compressibility Coefficient". That is, the compressibility coefficient of shale oil cores is tested according to the petroleum carbon dioxide industry standard SY / T 5815-2016 "Method for Determination of Rock Pore Volume Compressibility Coefficient" to obtain the rock pore compressibility coefficient (C). f ).

[0055] In an optional embodiment, the determination of the oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area includes:

[0056] Obtain the surface crude oil density corresponding to the aforementioned shale oil reservoir, and the target diffusion distance of the aforementioned carbon dioxide gas in the fractures of the aforementioned shale oil reservoir;

[0057] Based on the above-mentioned surface crude oil density, target diffusion distance, target fracture area, and oil increase per unit fracture area, the oil increase assessment results for the above-mentioned shale oil reservoir are determined.

[0058] Optionally, the target diffusion distance is the distance between the location where the carbon dioxide gas concentration in the fractures of the shale oil reservoir reaches a preset concentration after the carbon dioxide gas is injected into the shale oil reservoir and the well is shut off, and the fracture surface of the shale oil reservoir. That is, the target diffusion distance can be understood as the farthest distance the carbon dioxide gas diffuses in the fractures of the shale oil reservoir. The preset concentration may be, but is not limited to, 10%-5%.

[0059] It should be noted that the carbon dioxide gas concentration mentioned above is related to the well-closing time t and the diffusion depth (i.e., the distance from the fracture surface). Different well-closing times and / or diffusion depths correspond to different gas concentrations, such as... Figure 2a The relationship between diffusion depth and carbon dioxide gas concentration is shown for different well-closing times. It can be seen that different target diffusion distances can be obtained based on different well-closing times, and extraction... Figure 2a The relationship between the target diffusion distance and the well shut-in time is obtained when the carbon dioxide gas concentration reaches the preset concentration point. Figure 2b As shown.

[0060] Optionally, the oil increase assessment result of the above-mentioned shale oil reservoir can be determined based on the above-mentioned surface crude oil density, the above-mentioned target diffusion distance, the above-mentioned target fracture area, and the above-mentioned oil increase per unit fracture area using the following methods:

[0061]

[0062] Among them, A f The target crack area is given above, in meters. 2;ρ o The density of the crude oil on the ground is expressed in g / cm³ (grams per cubic centimeter); d is the target diffusion distance expressed in meters (m); q o (x) represents the oil increase per unit crack area, in tons (t). In an optional embodiment, the method further includes:

[0063] Obtain the above-mentioned surface crude oil density, diffusion depth, matrix overburden porosity, matrix bound water saturation, crude oil volume factor, and crude oil volume expansion factor corresponding to the above-mentioned shale oil reservoir;

[0064] Based on the above-mentioned surface crude oil density, diffusion depth, matrix overburden porosity, matrix bound water saturation, crude oil volume coefficient, and crude oil volume expansion factor, the above-mentioned increase in oil volume per unit fracture area is determined.

[0065] Optionally, the crude oil volume expansion factor is the expansion factor of the crude oil volume in the shale oil reservoir compared to before the injection of the carbon dioxide gas, after the carbon dioxide gas is injected into the shale oil reservoir and the shale oil reservoir is shut off. The crude oil volume expansion factor is dynamically changed with the diffusion depth of the carbon dioxide gas in the fractures of the shale oil reservoir.

[0066] Optionally, the oil gain per unit fracture area can be determined based on the above-mentioned surface crude oil density, diffusion depth, matrix overburden porosity, matrix bound water saturation, crude oil volume coefficient, and crude oil volume expansion factor in the following manner:

[0067]

[0068] Where, q o (x) represents the oil increase per unit crack area, in tons (t); ρ o The density of the above-mentioned crude oil on the ground is expressed in g / cm³. 3 (g / cm³); x represents the diffusion depth in meters (m); φ represents the matrix overburden porosity in percentage (%); S wi The above represents the bound water saturation of the matrix, in decimal form; B o V represents the above crude oil volume coefficient in decimal form; s (x) represents the volume expansion factor of the crude oil mentioned above, in decimal form.

[0069] In an optional embodiment, the above method further includes:

[0070] Acquire historical monitoring data within a preset time period, wherein the aforementioned historical monitoring data includes at least: first historical data determined based on the aforementioned crude oil volume expansion factor and the aforementioned carbon dioxide gas concentration, and second historical data determined based on the aforementioned diffusion depth and the aforementioned carbon dioxide gas concentration;

[0071] Based on the aforementioned first historical data, a first regression equation was determined between the aforementioned crude oil volume expansion factor and the aforementioned carbon dioxide gas concentration.

[0072] Based on the aforementioned second historical data, a second regression equation is determined between the aforementioned diffusion depth and the aforementioned carbon dioxide gas concentration;

[0073] Based on the first regression equation and the second regression equation, the crude oil volume expansion factor that varies with the diffusion depth is determined.

[0074] Optionally, the volume expansion factor of crude oil in shale reservoirs is related to the concentration of carbon dioxide gas (e.g., carbon dioxide gas), and the relationship between the two is as follows: Figure 3 As shown, there is also a certain relationship between the diffusion depth of carbon dioxide gas and its concentration. Based on historical monitoring data, a first relationship graph was plotted between the crude oil volume expansion factor and the carbon dioxide concentration. This first relationship graph was then fitted to obtain a first regression equation between the crude oil volume expansion factor and the carbon dioxide concentration. Based on historical monitoring data, a second relationship graph was plotted between the diffusion depth of carbon dioxide gas and its concentration. This second relationship graph was then fitted to obtain a second regression equation between the diffusion depth of carbon dioxide gas and its concentration. Solving the first and second regression equations simultaneously yielded the relationship equation between the diffusion depth of carbon dioxide gas and the crude oil volume expansion factor. Based on this equation, the crude oil volume expansion factor as a function of diffusion depth can be obtained.

[0075] This embodiment also provides a shale oil reservoir carbon dioxide huff and puff effect prediction device, which is used to implement the above embodiments and preferred embodiments, and will not be repeated as described above. As used below, the terms "module" and "device" can refer to a combination of software and / or hardware that performs a predetermined function. Although the device described in the following embodiments is preferably implemented in software, hardware implementation, or a combination of software and hardware, is also possible and contemplated.

[0076] According to an embodiment of the present invention, an apparatus embodiment for implementing the above-described method for predicting the carbon dioxide huff and puff effect in shale oil reservoirs is also provided. Figure 4This is a schematic diagram of a shale oil reservoir carbon dioxide huff and puff effect prediction device according to an embodiment of the present invention, as shown below. Figure 4 As shown, the above-mentioned shale oil reservoir carbon dioxide huff and puff effect prediction device includes: an acquisition module 400, a first determination module 402, and a second determination module 404, wherein:

[0077] The aforementioned acquisition module 400 is used to acquire the oil increase per unit fracture area of ​​a shale oil reservoir, wherein the oil increase per unit fracture area is dynamically changed with the diffusion depth of carbon dioxide gas in the fractures of the aforementioned shale oil reservoir, and the aforementioned carbon dioxide gas is pre-injected into the aforementioned shale oil reservoir.

[0078] The first determining module 402 is connected to the acquisition module 400 and is used to determine the target fracture area of ​​the shale oil reservoir, wherein the target fracture area changes dynamically with the cumulative well opening time of the shale oil reservoir.

[0079] The second determining module 404 is connected to the first determining module 402 and is used to determine the oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area; and to determine the carbon dioxide huff and puff effect of the shale oil reservoir based on the oil increase assessment result.

[0080] In this embodiment of the invention, the acquisition module 400 is configured to acquire the oil increase per unit fracture area of ​​a shale oil reservoir, wherein the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; the first determining module 402 is configured to determine the target fracture area of ​​the shale oil reservoir, wherein the target fracture area is dynamically varied with the cumulative well operating time of the shale oil reservoir; the second determining module 404 is configured to determine the target fracture area and the oil increase per unit fracture area based on the target fracture area and the oil increase per unit fracture area. The oil increase in area was determined, and the oil increase assessment results of the above-mentioned shale oil reservoirs were determined based on the oil increase assessment results. Based on the above oil increase assessment results, the carbon dioxide huff and puff effect of the above-mentioned shale oil reservoirs was determined. This achieved the goal of comprehensively considering the factors of gas diffusion and dynamic changes in fracture area to determine the carbon dioxide huff and puff effect of shale oil reservoirs. This improved the technical effect of improving the prediction efficiency and accuracy of carbon dioxide huff and puff effect of shale oil reservoirs. In addition, it solved the technical problems of large calculation volume, long time consumption, difficulty in fracture characterization, and inaccurate assessment that exist in related technologies, which mainly rely on conventional reservoir numerical simulation methods to determine the carbon dioxide huff and puff effect of shale oil reservoirs.

[0081] It should be noted that the above modules can be implemented by software or hardware. For example, for the latter, it can be implemented in the following ways: the above modules can be located in the same processor; or the above modules can be located in different processors in any combination.

[0082] It should be noted that the aforementioned acquisition module 400, first determination module 402, and second determination module 404 correspond to steps S102 to S106 in the embodiments. The instances and application scenarios implemented by the above modules and their corresponding steps are the same, but are not limited to the content disclosed in the above embodiments. It should also be noted that the above modules, as part of the device, can run in a computer terminal.

[0083] It should be noted that the optional or preferred implementation methods of this embodiment can be found in the relevant descriptions in the embodiments, and will not be repeated here.

[0084] The aforementioned shale oil reservoir carbon dioxide huff and puff effect prediction device may also include a processor and a memory. The aforementioned acquisition module 400, first determination module 402, second determination module 404, etc., are all stored in the memory as program modules, and the processor executes the aforementioned program modules stored in the memory to realize the corresponding functions.

[0085] The processor contains a core that retrieves the corresponding program modules from memory. One or more cores may be configured. Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM. Memory includes at least one memory chip.

[0086] According to an embodiment of this application, an embodiment of a non-volatile storage medium is also provided. Optionally, in this embodiment, the non-volatile storage medium includes a stored program, wherein, when the program runs, it controls the device containing the non-volatile storage medium to execute any of the aforementioned shale oil reservoir carbon dioxide huff and puff effect prediction methods.

[0087] Optionally, in this embodiment, the non-volatile storage medium may be located in any computer terminal in a group of computer terminals in a computer network, or in any mobile terminal in a group of mobile terminals, and the non-volatile storage medium includes stored programs.

[0088] Optionally, during program execution, the device containing the non-volatile storage medium may be controlled to perform the following functions: obtain the oil increase per unit fracture area of ​​the shale oil reservoir, wherein the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determine the target fracture area of ​​the shale oil reservoir, wherein the target fracture area is dynamically varied with the cumulative well operating time of the shale oil reservoir; based on the target fracture area and the oil increase per unit fracture area, determine the oil increase assessment result of the shale oil reservoir; and based on the oil increase assessment result, determine the carbon dioxide huff and puff effect of the shale oil reservoir.

[0089] According to an embodiment of this application, an embodiment of a processor is also provided. Optionally, in this embodiment, the processor is used to run a program, wherein the program executes any of the above-described methods for predicting the carbon dioxide huff and puff effect of shale oil reservoirs.

[0090] According to an embodiment of this application, an embodiment of a computer program product is also provided, which, when executed on a data processing device, is adapted to execute a program that initializes the carbon dioxide huff and puff effect prediction method steps of any of the above-described methods for shale oil reservoirs.

[0091] Optionally, when the aforementioned computer program product is executed on a data processing device, it is suitable to execute an initialization program comprising the following steps: obtaining the oil increase per unit fracture area of ​​the shale oil reservoir, wherein the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining the target fracture area of ​​the shale oil reservoir, wherein the target fracture area is dynamically varied with the cumulative well operating time of the shale oil reservoir; determining the oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area; and determining the carbon dioxide huff and puff effect of the shale oil reservoir based on the oil increase assessment result.

[0092] like Figure 5As shown, an embodiment of the present invention provides an electronic device 10, which includes a processor, a memory, and a program stored in the memory and executable on the processor. When the processor executes the program, it performs the following steps: obtaining the oil increase per unit fracture area of ​​a shale oil reservoir, wherein the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining the target fracture area of ​​the shale oil reservoir, wherein the target fracture area is dynamically varied with the cumulative well operating time of the shale oil reservoir; determining the oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area; and determining the carbon dioxide huff and puff effect of the shale oil reservoir based on the oil increase assessment result.

[0093] The sequence numbers of the above embodiments of the present invention are for descriptive purposes only and do not represent the superiority or inferiority of the embodiments.

[0094] In the above embodiments of the present invention, the descriptions of each embodiment have different focuses. For parts not described in detail in a certain embodiment, please refer to the relevant descriptions of other embodiments.

[0095] In the several embodiments provided in this application, it should be understood that the disclosed technical content can be implemented in other ways. The device embodiments described above are merely illustrative; for example, the division of modules described above can be a logical functional division, and in actual implementation, there may be other division methods. For example, multiple modules or components may be combined or integrated into another system, or some features may be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection shown or discussed may be through some interfaces, or indirect coupling or communication connection between modules, and may be electrical or other forms.

[0096] The modules described above as separate components may or may not be physically separate. Similarly, the components shown as modules may or may not be physical modules; they may be located in one place or distributed across multiple modules. Some or all of the modules can be selected to achieve the purpose of this embodiment, depending on actual needs.

[0097] Furthermore, the functional modules in the various embodiments of the present invention can be integrated into one processing module, or each module can exist physically separately, or two or more modules can be integrated into one module. The integrated modules described above can be implemented in hardware or as software functional modules.

[0098] If the integrated modules described above are implemented as software functional modules and sold or used as independent products, they can be stored in a computer-readable non-volatile storage medium. Based on this understanding, the technical solution of this invention, in essence, or the part that contributes to the prior art, or all or part of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a non-volatile storage medium and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute all or part of the steps of the methods of the various embodiments of this invention. The aforementioned non-volatile storage medium includes various media capable of storing program code, such as USB flash drives, read-only memory (ROM), random access memory (RAM), portable hard drives, magnetic disks, or optical disks.

[0099] The above are merely preferred embodiments of the present invention. It should be noted that those skilled in the art can make various improvements and modifications without departing from the principle of the present invention, and these improvements and modifications should also be considered within the scope of protection of the present invention.

Claims

1. A method for predicting the carbon dioxide huff and puff effect in shale oil reservoirs, characterized in that, include: The oil increase per unit fracture area in a shale oil reservoir is obtained, wherein the oil increase per unit fracture area is dynamically varied with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir. Determine the target fracture area of ​​the shale oil reservoir, wherein the target fracture area dynamically changes with the cumulative well operating time of the shale oil reservoir; Based on the target fracture area and the oil increase per unit fracture area, the oil increase assessment result of the shale oil reservoir is determined; based on the oil increase assessment result, the carbon dioxide huff and puff effect of the shale oil reservoir is determined. The step of determining the target fracture area of ​​the shale oil reservoir includes: acquiring the production history data of the shale oil reservoir, wherein the production history data includes at least: the crude oil production, water cut, formation pressure and bottom hole flow pressure of the shale oil reservoir; and determining the target fracture area based on the production history data. The step of determining the oil increase assessment result of the shale oil reservoir based on the target fracture area and the oil increase per unit fracture area includes: obtaining the surface crude oil density corresponding to the shale oil reservoir, and the target diffusion distance of carbon dioxide gas in the fractures of the shale oil reservoir, wherein the target diffusion distance is the distance between the location where the concentration of carbon dioxide gas in the fractures of the shale oil reservoir reaches a preset concentration after the carbon dioxide gas is injected into the shale oil reservoir and the well is shut off, and the fracture surface of the shale oil reservoir; and determining the oil increase assessment result of the shale oil reservoir based on the surface crude oil density, the target diffusion distance, the target fracture area, and the oil increase per unit fracture area.

2. The method according to claim 1, characterized in that, Determining the target crack area based on the production history data includes: Based on the aforementioned production history data, the areas of multiple cracks at different historical moments were calculated. Select the crack area whose moisture content is within a first preset range from the plurality of crack areas; The average value of the crack area corresponding to the moisture content being within a first preset range is determined, and the average value is used as the target crack area.

3. The method according to claim 2, characterized in that, Based on the production history data, the areas of multiple cracks at different historical moments are obtained, including: The reservoir physical property parameters, crude oil high pressure physical property parameters, and cumulative well opening time corresponding to the shale oil reservoir are obtained. The reservoir physical property parameters include at least: crude oil saturation pressure, crude oil compressibility, formation volume factor, and formation crude oil viscosity. The reservoir physical property parameters include at least: matrix overburden permeability, matrix overburden porosity, and bound water saturation. Based on the production history data, reservoir properties, high-pressure crude oil properties, and cumulative well opening time, multiple fracture areas at different historical moments are obtained as follows: in, This represents the area of ​​the crack at different historical moments. This indicates the crude oil production. This represents the formation volume factor. This indicates the formation pressure. This indicates the bottom hole flow pressure. This indicates the viscosity of the crude oil in the formation. This indicates the cumulative well-opening time. This indicates the permeability of the matrix under pressure. This indicates the porosity of the matrix covering. The comprehensive compressibility factor is defined as the overall compressibility factor, which is determined based on the crude oil compressibility factor and the bound water saturation.

4. The method according to claim 1, characterized in that, The oil gain assessment result of the shale oil reservoir is determined based on the surface crude oil density, the target diffusion distance, the target fracture area, and the oil gain per unit fracture area using the following method: ； in, Let be the area of ​​the target crack. Let d be the density of the crude oil on the ground, and d be the target diffusion distance. The amount of oil added per unit crack area.

5. The method according to claim 1, characterized in that, The method further includes: The following parameters are obtained for the shale oil reservoir: surface crude oil density, diffusion depth, matrix overburden porosity, matrix bound water saturation, crude oil volume coefficient, and crude oil volume expansion factor. The crude oil volume expansion factor is the expansion factor of the crude oil volume in the shale oil reservoir compared to before the carbon dioxide gas injection, after the carbon dioxide gas is injected into the shale oil reservoir and the reservoir is subjected to a well-clogging treatment. The crude oil volume expansion factor dynamically changes with the diffusion depth of carbon dioxide gas in the fractures of the shale oil reservoir. The amount of oil added per unit fracture area is determined based on the surface crude oil density, the diffusion depth, the matrix overburden porosity, the matrix bound water saturation, the crude oil volume coefficient, and the crude oil volume expansion factor.

6. The method according to claim 5, characterized in that, The oil gain per unit fracture area is determined based on the surface crude oil density, the diffusion depth, the matrix overburden porosity, the matrix bound water saturation, the crude oil volume coefficient, and the crude oil volume expansion factor, using the following method: ； in, This represents the increase in oil volume per unit crack area. This indicates the density of the crude oil on the ground. Indicates the diffusion depth. This indicates the porosity of the matrix covering. This indicates the saturation of bound water in the matrix. This represents the crude oil volume coefficient. This indicates the volume expansion factor of the crude oil.

7. A device for predicting the carbon dioxide huff and puff effect in shale oil reservoirs, characterized in that, The device is used to perform the method for predicting the carbon dioxide huff and puff effect of shale oil reservoirs as described in any one of claims 1 to 6.

8. A non-volatile storage medium, characterized in that, The non-volatile storage medium stores multiple instructions, which are adapted to be loaded and executed by a processor using the shale reservoir carbon dioxide huff and puff effect prediction method according to any one of claims 1 to 6.

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