A method and device for predicting the productivity of carbon dioxide huff and puff recovery

Abstract

The application discloses a kind of carbon dioxide huff and puff production capacity prediction method and device.The method comprises, after carbon dioxide huff and puff injection, according to carbon dioxide injection amount, reconstruction area volume and crack volume and original porosity, update each phase saturation and formation pressure;In the well soaking stage, iteration is executed: according to current formation pressure and temperature, determine the solubility of carbon dioxide in crude oil, according to the solubility and carbon dioxide injection amount, update current each phase saturation, until well soaking ends, according to current solubility and oil saturation, update crude oil viscosity;In the well production stage, iteration is executed: according to current crude oil viscosity, carbon dioxide solubility and each phase relative permeability, the yield determined by five-zone linear flow productivity model is multi-phase splitting, to obtain each phase cumulative production, and then update current each phase saturation.The method deduces the pressure and saturation change of three stages of gas injection huff and puff, and deduces the CO2 huff and puff productivity in combination with five-zone linear flow productivity model.

Description

Technical Field

[0001] This invention relates to the field of unconventional oil and gas reservoir development technology, and in particular to a method and apparatus for predicting carbon dioxide huff and puff production capacity. Background Technology

[0002] Horizontal well volumetric fracturing technology has become the main development technology for unconventional oil reservoirs such as tight oil and shale oil, significantly improving single-well productivity. However, it generally suffers from problems such as rapid production decline, difficulty in stabilizing production, and low recovery rates. To address the issue of improving recovery rates in unconventional oil reservoirs, domestic and international scholars have conducted extensive research on gas injection huff and puff, demonstrating that it can improve single-well production and recovery rates. Pilot gas injection huff and puff tests have also yielded positive results. However, current research methods primarily rely on laboratory experiments and numerical simulations. Laboratory experiments focus on the development mechanism of gas injection huff and puff, while numerical simulations require precise geological models and have long research cycles. Domestic and international scholars have also conducted extensive research on productivity equations for unconventional oil reservoirs, but most studies predict the initial productivity of wells after volumetric fracturing. There is a lack of productivity equations that provide a detailed description of the entire gas injection huff and puff process, which would allow for rapid prediction of development indicators and recovery rates to guide development and production. Summary of the Invention

[0003] In view of the above problems, the present invention is proposed to provide a method and apparatus for predicting carbon dioxide injection production capacity to overcome or at least partially solve the above problems. The invention reasonably derives the pressure and saturation changes in the three stages of gas injection and injection, and derives the CO2 injection capacity by combining a five-zone linear flow production capacity model.

[0004] In a first aspect, embodiments of the present invention provide a method for predicting carbon dioxide huff and puff production capacity, comprising:

[0005] After carbon dioxide injection, the water, oil, and gas saturation and formation pressure of the modified zone are updated based on the carbon dioxide injection volume, fracture volume in the reservoir modification zone, volume of the modified zone, original formation pressure, water saturation, oil saturation, and porosity.

[0006] During the well shut-in phase, the following steps are performed at the first set interval: the solubility of carbon dioxide in crude oil is determined based on the current formation pressure and temperature; the current water content, oil content and gas content saturation are updated based on the solubility, the current oil saturation and the amount of carbon dioxide injected, until the well shut-in phase ends; and the current crude oil viscosity is determined based on the current solubility and oil saturation.

[0007] During the well opening and production phase, the following steps are performed at the second set interval: Based on the current crude oil viscosity, the solubility of carbon dioxide in crude oil, and the relative permeability of each phase under the current saturation conditions, the current production determined by the five-zone linear flow production capacity model is split into multiple phases to obtain the production capacity of each phase, and the cumulative production of each phase after well opening and production is obtained. Based on the cumulative production of each phase and the current oil saturation, the current water, oil, and gas saturation are updated.

[0008] Secondly, embodiments of the present invention provide a carbon dioxide huff and puff production capacity prediction device, comprising:

[0009] The physical field update module after carbon dioxide huff and puff injection is used to update the water, oil and gas saturation and formation pressure of the modified zone based on the carbon dioxide injection amount, fracture volume in the reservoir modified zone, volume of the modified zone, original formation pressure, water saturation, oil saturation and porosity after carbon dioxide huff and puff injection.

[0010] The physical field update module for the stalemate stage is used to perform the following steps at a first set interval during the stalemate stage: determine the solubility of carbon dioxide in crude oil based on the current formation pressure and temperature; update the current water content, oil content and gas content saturation based on the solubility, the current oil saturation and the amount of carbon dioxide injected, until the end of the stalemate stage; and determine the current crude oil viscosity based on the current solubility and oil saturation.

[0011] The physical field update and phase production prediction module for the well opening production stage is used to perform the following steps at a second set interval during the well opening production stage: based on the current crude oil viscosity, carbon dioxide solubility in crude oil, and relative permeability of each phase under the current saturation conditions, the current production determined by the five-zone linear flow production capacity model is multiphase split to obtain the production capacity of each phase, the cumulative production of each phase after well opening production is obtained, and the current water, oil, and gas saturation is updated based on the cumulative production of each phase and the current oil saturation.

[0012] Thirdly, embodiments of the present invention provide a computer program product, including a computer program / instruction, wherein the computer program / instruction, when executed by a processor, implements the above-mentioned carbon dioxide throughput mining capacity prediction method.

[0013] Fourthly, embodiments of this disclosure provide a server, including: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the program to implement the above-described method for predicting carbon dioxide throughput and extraction capacity.

[0014] The beneficial effects of the above-described technical solutions provided in the embodiments of the present invention include at least the following:

[0015] (1) The carbon dioxide injection production capacity prediction method provided in this embodiment of the invention starts from the injection injection mechanism, considers the energy replenishment and dissolution viscosity reduction mechanism of CO2 injection injection, divides the injection injection into the energy replenishment stage, the well-sealing dissolution viscosity reduction stage and the well-opening recovery three-phase flow stage, and derives the pressure and saturation change equations for these three stages respectively, and derives the CO2 injection production capacity equation by combining the five-zone linear flow production capacity model of horizontal well volume fracturing.

[0016] (2) Currently, the main application software programs used for CO2 huff and puff research, such as large-scale commercial numerical simulation software like Intersect and Eclipse, employ numerical simulation calculation methods. These software programs are expensive, have high requirements for the operating environment, require large amounts of data, and involve long research periods. The CO2 huff and puff production capacity prediction method provided in this embodiment of the invention targets unconventional oil reservoirs using CO2 huff and puff for energy supplementation. It uses analytical methods to evaluate well production capacity and has the advantages of being more targeted, having lower operating costs, faster operating speed, and being easier to use compared to large-scale numerical simulation software. It can evaluate the CO2 huff and puff production capacity of different types of unconventional oil reservoirs. The calculation method is simple, fast, and efficient, making it more suitable for rapid evaluation and comparison of unconventional oil reservoir development methods and the formulation of development technology policies. It covers unconventional oil reservoir resources amounting to hundreds of billions of tons and has broad application prospects.

[0017] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description, claims, and drawings.

[0018] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0019] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0020] Figure 1 This is a schematic diagram of the reservoir region division after volumetric fracturing in Embodiment 1 of the present invention;

[0021] Figure 2 This is a schematic diagram of reservoir seepage during the gas injection energy replenishment stage in Embodiment 1 of the present invention;

[0022] Figure 3 This is a schematic diagram of reservoir seepage during the dissolution and viscosity reduction stage in a sealed well, as described in Embodiment 1 of the present invention.

[0023] Figure 4This is a schematic diagram of reservoir seepage during the three-phase flow stage of well opening and recovery in Embodiment 1 of the present invention;

[0024] Figure 5 This is a flowchart of the carbon dioxide throughput mining capacity prediction method in Embodiment 1 of the present invention;

[0025] Figure 6 for Figure 5 The detailed implementation flowchart of step S51 is shown below;

[0026] Figure 7 This is a flowchart illustrating the specific implementation of crude oil viscosity updating after well shut-in in Embodiment 1 of the present invention.

[0027] Figure 8 Comparison of gas injection throughput calculated using analytical models with numerical simulations;

[0028] Figure 9 The analytical model was used to calculate the formation pressure during gas injection and discharge, and the results were compared with those from numerical simulations.

[0029] Figure 10 This is a flowchart illustrating the specific implementation of carbon dioxide throughput and extraction capacity prediction in this embodiment of the invention.

[0030] Figure 11 This is a comparison curve of CO2 injection volume and cumulative oil production per well in the Lucao Gou Formation in Embodiment 2 of the present invention.

[0031] Figure 12 This is a schematic diagram of the carbon dioxide throughput and extraction capacity prediction device in an embodiment of the present invention. Detailed Implementation

[0032] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0033] Due to horizontal well CO 2 The complexity of the gas injection and production mechanism and process means that an analytical productivity equation reflecting this complexity is still lacking. The technical problems that need to be solved include:

[0034] ① Mechanism and Mathematical Equations of CO2 Injection and Packing Development in Volumetric Reservoirs

[0035] CO2 injection huff and puff has many extraction mechanisms, including energy replenishment, viscosity reduction, miscibility, and changes in reservoir wettability. Considering all CO2 injection huff and puff extraction mechanisms would make the analytical equations extremely complex and unsolvable. How to reflect the main extraction mechanisms of CO2 huff and puff in unconventional reservoirs and describe the mechanisms with mathematical models is a key technical problem that needs to be solved.

[0036] ② Coupled productivity equations for multi-scale porous fracture systems in horizontal well volumetric fracturing

[0037] Due to the poor reservoir properties of unconventional oil reservoirs, horizontal wells require volumetric fracturing to achieve natural production capacity. After volumetric fracturing, the reservoir generates a large number of fractures, transforming the reservoir near the wellbore into a pseudo-dual-medium reservoir. The reservoir seepage pattern is fundamentally changed, and the fractures and natural fractures form a complex fracture network system. How to consider the coupling relationship between fractures, natural fractures and matrix, and establish a production capacity equation for the multi-scale pore fracture system of horizontal well volumetric fracturing, is a key technical problem that needs to be solved.

[0038] ③ Equations reflecting reservoir pressure and saturation changes over multiple CO2 injection cycles

[0039] CO2 injection huff and puff differs from CO2 displacement. In huff and puff, the reservoir pressure and oil-water saturation change with each injection and production cycle, and the fluid displacement effect decreases with the increase of the huff and puff cycle. How to consider the formation pressure distribution field and oil-water saturation field throughout the huff and puff process is a key technical problem that needs to be solved.

[0040] To address the issue that existing production capacity equations mostly predict the initial production capacity of oil wells after volumetric fracturing, lacking a prediction of production capacity throughout the entire gas injection and huffing process, this invention provides a method and apparatus for predicting CO2 huffing and huffing production capacity. This method can reasonably predict the pressure and saturation changes in the three stages of gas injection and huffing, and derive the CO2 huffing and huffing production capacity by combining a five-zone linear flow production capacity model.

[0041] 1. Research on the main development mechanism of CO2 injection huff and puff in volumetric fracturing

[0042] CO2 injection huff and puff has many extraction mechanisms, including energy replenishment, viscosity reduction, miscibility, and alteration of reservoir wettability. Based on current research findings both domestically and internationally, the dominant extraction mechanism of CO2 injection huff and puff in China's continental unconventional reservoirs is considered to include two aspects: first, the energy replenishment mechanism of CO2, which refers to the fact that CO2 gas injected into the formation has a low density and large volume, thus playing a good role in replenishing formation energy; second, the viscosity reduction mechanism of CO2, which refers to the fact that CO2 dissolves into crude oil, reducing crude oil viscosity, significantly increasing crude oil fluidity, and thus improving single-well productivity.

[0043] In this embodiment of the invention, the volumetrically modified reservoir is simplified into three regions based on the degree of modification: the main fracture zone, the volumetrically modified zone (referred to as the modified zone), and the unmodified zone. (Refer to...) Figure 1 As shown.

[0044] 2. Physical process and simplified model of gas injection and pneumatic fracturing

[0045] Based on the gas injection huff and puff mechanism, considering the two main production mechanisms of CO2 gas injection huff and puff—energy replenishment and dissolution / viscosity reduction—the physical process of gas injection huff and puff in volumetric fracturing reservoirs is divided into three stages: the energy replenishment stage, the well-sealing dissolution / viscosity reduction stage, and the well-opening production three-phase flow stage. The first stage is the energy replenishment stage. Due to the high permeability of the main fracture zone and the volumetric fracturing zone, the injected gas first enters the fracture and then rapidly enters the volumetric fracturing zone. Because of the rapid gas diffusion rate, it can be assumed that the gas is uniformly distributed in the control volume. Simultaneously, because the permeability of the unfracturing zone is extremely low, this model assumes that the injected gas exists entirely in the volumetric fracturing zone and does not enter the unfracturing zone. However, pressure transmission may exist between the volumetric fracturing zone and the unfracturing zone. (See...) Figure 2 As shown; the second stage is the well-drain dissolution and viscosity reduction stage. During this stage, gas injection stops, and CO2 in the modified zone gradually dissolves into the crude oil, becoming dissolved gas. This leads to changes in both the crude oil properties and oil saturation. Simultaneously, some CO2 remains undissolved in the crude oil and exists as free CO2 in the modified zone. (See...) Figure 3 As shown; the third stage is the three-phase flow stage of well opening and recovery. In this stage, the well is opened and recovered after the initial shut-in period. Fluid first flows into the wellbore from the main fracture and is then extracted. Then, fluid from the stimulated volume begins to flow into the main fracture zone. Finally, the formation pressure in the stimulated zone decreases, and fluid from the unstimulated zone also begins to flow into the stimulated zone. (See...) Figure 4 As shown.

[0046] Example 1

[0047] Embodiment 1 of the present invention provides a method for predicting the production capacity of carbon dioxide huff and puff extraction, the process of which is as follows: Figure 5 As shown, it includes the following steps:

[0048] Step S51: After carbon dioxide huff and puff injection, update the water, oil, and gas saturation and formation pressure of the stimulated zone based on the carbon dioxide injection volume, fracture volume in the reservoir stimulation zone, volume of the stimulation zone, original formation pressure, water saturation, oil saturation, and porosity.

[0049] Assuming the fluid injection process is instantaneous, and given the rapid gas diffusion rate, it can be considered uniformly distributed within the control volume and the modified region. The model considers the viscosity reduction effect caused by carbon dioxide dissolution or miscibility. See [link to relevant documentation]. Figure 6 As shown, the formation physical field update after gas injection to replenish energy includes the following steps:

[0050] Step S511: Determine the original water content and oil content of the modified area before carbon dioxide huff and puff injection based on the volume of the modified area, the original water saturation, the oil saturation and porosity.

[0051] The original water content and oil content of the modified zone before carbon dioxide huff and puff injection can be determined by the following formulas (1) and (2):

[0052]

[0053]

[0054] In formulas (1) and (2), W i and N i These represent the original water content and oil content of the modified area, respectively, and V. t For the volume of the modification area, φ i To modify the original porosity of the area, and These represent the original water content and oil saturation of the remediation area, respectively, and B. w and B o These are the volume coefficients for the aqueous phase and the oil phase, respectively.

[0055] Step S512: Update the water content, oil content, and gas saturation of the modified area based on the amount of carbon dioxide injected and the original water and oil content of the modified area.

[0056] Based on the amount of carbon dioxide injected and the original water and oil content of the modified area, the water, oil, and gas saturation of the modified area can be updated using the following formulas (3)-(5):

[0057]

[0058]

[0059]

[0060] In formulas (3)-(5), and These represent the updated water, oil, and gas saturation levels of the modified area, W. i and N i These are the original water content and oil content of the remediation area, respectively, B w B o and B g V represents the volume index of the aqueous phase, oil phase, and gas phase, respectively. injg_sc This refers to the ground volume injected with carbon dioxide.

[0061] Step S513: Based on the carbon dioxide injection amount, fracture volume in the modified zone, volume of the modified zone, original formation pressure, porosity, and updated water, oil, and gas saturation, update the formation pressure of the modified zone.

[0062] The formation pressure in the modified area can be updated using the following formula (6):

[0063]

[0064] In formula (6), p0 represents the updated formation pressure, p0 represents the original formation pressure of the modified zone, and c represents the original formation pressure. w c o c g c F and c r These are the compressibility coefficients of the aqueous phase, oil phase, gas phase, cracks, and matrix in the modified zone, respectively. and These are the updated water content, oil content, and gas saturation, respectively, V t V represents the volume of the modified area. F φ represents the volume of the cracks in the modified area. i To modify the original porosity of the area, B g is the volume coefficient of the gas phase.

[0065] Furthermore, the above formula (6) can be derived through the following process:

[0066] After gas injection, the underground volume V of the injected gas inj Equal to the volume compression ΔV of underground oil o The volumetric compression of groundwater ΔV w Volume compression of underground gas ΔV g The increase in pore volume ΔV p The sum of the four is:

[0067] V inj =ΔV o +ΔV w +ΔV p +ΔV g (7)

[0068] in,

[0069] V inj =V injg_sc B g (8)

[0070] In formula (8), B g It is the volume coefficient of the gas.

[0071] ΔV w =cw V t φ i S w (p a -p i (9)

[0072] In formula (9), c e V is the compressibility coefficient of water. t It is the volume of the modified area, φ i S represents the average porosity of the reservoir in its original state (which needs to be weighted using different fractured reservoir characteristics). w p represents water saturation. a p is the average formation pressure at the end of injection. i This represents the original formation pressure.

[0073] Since it is assumed that the fluid injection process is completed instantaneously, it can be considered that the gas has not yet begun to dissolve after the injection is completed. Therefore:

[0074] ΔV o =c o V t φ i S o (p a -p i (10)

[0075] In formula (10), c o It is the compressibility coefficient of oil, S o This represents the oil saturation level.

[0076] ΔV p =[c F V F +c r (V t -V F )](p a -p i (11)

[0077] In formula (11), c F It is the compressibility coefficient of the fractured medium, c r The compressibility coefficient of matrix rock, V F It is the volume of the crack.

[0078] ΔV g =c g V t φ i S g (p a -p i (12)

[0079] In formula (12), c gIt is the compressibility coefficient of the gas, S g This represents the saturation level of undissolved carbon dioxide in the oil layer before gas injection.

[0080] Since the gas has not yet begun to dissolve after injection, substituting equations (8) to (12) into equation (7) yields the average formation pressure after gas injection:

[0081]

[0082] Step S52: During the well shut-in phase, perform the following steps at the first set interval: Determine the solubility of carbon dioxide in crude oil based on the current formation pressure and temperature; update the current water content, oil content, and gas content saturation based on the solubility, the current oil saturation, and the amount of carbon dioxide injected, until the well shut-in phase ends; and determine the current crude oil viscosity based on the current solubility and oil saturation.

[0083] Considering the solubility characteristics of carbon dioxide, during the well-sealing process, some carbon dioxide gradually dissolves into the crude oil, reducing its viscosity. Ultimately, a portion of the carbon dioxide dissolves in the crude oil, while the remainder is stored as free gas within the pores of the porous medium. The solubility of carbon dioxide in crude oil is defined as the volume of gas dissolved in a unit volume of crude oil at a given temperature, denoted by Gc, and measured in cubic meters (m³). 3 / m 3 The solubility is mainly related to the properties of the crude oil, pressure, and temperature, and needs to be determined through laboratory experiments. The following formula is provided for reference:

[0084] G c =-56.63+3.227T+14.83p-0.05476T 2 -0.3718Tp + 1.207p 2 +0.0003T 3 +0.002803T 2 p-0.006063Tp 2 -0.03827p 3 (14)

[0085] In formula (14), T is temperature in °C; p is pressure in MPa. It is assumed that the formation pressure in the reformed area remains unchanged during the well shut-in process, which is consistent with the pressure before the well shut-in after the carbon dioxide injection. The constants in formula (14) are experimental fitting values ​​and are only an illustration. The fitting values ​​of each constant may also change accordingly after changes in crude oil properties or other related conditions.

[0086] Based on the currently determined solubility, current oil saturation, and carbon dioxide injection amount, the current water, oil, and gas saturations can be further updated using formulas (15)-(17):

[0087]

[0088]

[0089]

[0090] In formulas (15)-(17), and These are the updated water content, oil content, and gas saturation, respectively, W. i and N i These are the original water content and oil content of the remodeling area. and These represent the original water content and oil saturation of the remediation area, respectively, and B. w B o and B g V represents the volume index of the aqueous phase, oil phase, and gas phase, respectively. injg_sc S represents the ground volume of injected carbon dioxide. o Given the current oil saturation, G c This represents the current solubility of carbon dioxide in crude oil.

[0091] After the well-sealing phase is completed, see Figure 7 As shown, the current crude oil viscosity can be updated through the following steps:

[0092] Step S71: Determine the mole fraction of carbon dioxide in the crude oil based on the current solubility and oil saturation.

[0093] Based on the current solubility and oil saturation, the mole fraction of carbon dioxide in crude oil is determined using the following formula (18):

[0094]

[0095] In formula (18), x i G represents the mole fraction of carbon dioxide in crude oil. c This represents the current solubility of carbon dioxide in crude oil. V represents the current oil saturation level. m M is the molar volume of the gas, in mol / L; o The average molecular weight of crude oil is ρ (g / mol). o V is the density of crude oil; t For the volume of the modification area; φ i This represents the original porosity of the modified area. (Except for V) m and M o Apart from that, all other parameters are in SI units.

[0096] Step S72: Determine the current crude oil viscosity based on the mole fraction of carbon dioxide in the crude oil and the current temperature.

[0097] Based on the mole fraction of carbon dioxide in the crude oil and the current temperature, the current crude oil viscosity is determined using formula (19):

[0098] lnμ o =(1-x i )lnμ T +x i (lnμ c +a+b ln T) (19)

[0099] In formula (19), μ o x represents the current crude oil viscosity. i The value is the mole fraction of carbon dioxide in the crude oil, T is the current temperature, and μ is the value. T Let μ be the viscosity of crude oil at temperature T without the presence of carbon dioxide. c Let μ be the viscosity of carbon dioxide at the current temperature. o μ T and μ c The units are all in mPa·s; a and b are influence coefficients, which can be obtained from experimental data. Here, a = 14.5 and b = -1.8 can be taken. The first term on the right side of the formula means the effect of heating viscosity reduction on the final crude oil viscosity, the second term means the effect of carbon dioxide viscosity on the final crude oil viscosity, and the b ln T term indicates that the viscosity reduction effect of carbon dioxide is affected by temperature.

[0100] The viscosity of carbon dioxide can be calculated using the following formula according to the gas handbook:

[0101] u c =10 -4 ·(11.336+4.9918×10 -01 (T+273.15)-1.0876×10 -04 (T+273.15) 2 (20).

[0102] Step S53: During the well opening and production phase, perform the following steps at the second set interval: Based on the current crude oil viscosity, the solubility of carbon dioxide in crude oil, and the relative permeability of each phase under the current saturation conditions, perform multiphase splitting on the current production determined by the five-zone linear flow production capacity model to obtain the production capacity of each phase, obtain the cumulative production of each phase after well opening and production, and update the current water, oil, and gas saturation based on the cumulative production of each phase and the current oil saturation.

[0103] Specifically, the current production capacity determined by the five-zone linear flow production capacity model can be multiphase split according to the following formulas (21)-(23) to obtain the current production capacity of the aqueous phase, oil phase and gas phase:

[0104]

[0105]

[0106]

[0107] In formulas (21)-(23), q t The current output determined by the five-zone linear flow capacity model should be noted. It should be explained that the unmodified zone in the five-zone linear flow capacity model is divided into three parts. In this embodiment, one unmodified zone, i.e., the third region, represents the three unmodified zones of the five-zone capacity model. This is to simplify the derivation process of the gas injection throughput capacity and does not affect the capacity calculation; q w q o and q g These represent the current production capacity of the aqueous phase, oil phase, and gas phase, respectively; k rw k ro and k rg These represent the relative permeabilities of the aqueous, oil, and gas phases under the current saturation conditions, respectively, and can be obtained experimentally; μ o Given the current crude oil viscosity, μ w and μ g The viscosities of the aqueous and gaseous phases, B w B o and B g G represents the volume factors for the aqueous phase, oil phase, and gas phase, respectively. c This represents the current solubility of carbon dioxide in crude oil.

[0108] Furthermore, based on the cumulative yield of each phase and the current oil saturation, the current water, oil, and gas saturations can be updated using the following formulas (24)-(26):

[0109]

[0110]

[0111]

[0112] In formulas (24)-(26), and These are the updated water content, oil content, and gas saturation, S. o Given the current oil saturation, W p N p and G p The cumulative yields for the aqueous phase, oil phase, and gas phase are respectively, B w B o and B g G represents the volume factors for the aqueous phase, oil phase, and gas phase, respectively. c V represents the current solubility of carbon dioxide in crude oil. tLet φ be the volume of the modified area. i V represents the original porosity of the modified area. injg_sc W represents the ground volume of carbon dioxide injected. i and N i These are the original water content and oil content of the modified area, respectively. and These refer to the original water content and oil saturation of the modified area, respectively.

[0113] In some embodiments, after updating the current water, oil, and gas saturations based on the cumulative yield of each phase and the current oil saturation, the method may further include:

[0114] The formation pressure is updated based on the cumulative production of each phase and the updated water, oil, and gas saturation.

[0115] Specifically, based on the cumulative production of each phase and the updated water, oil, and gas saturation, the formation pressure is updated using the following formula (27):

[0116]

[0117] In formula (27), Here, p represents the updated formation pressure, and c represents the current formation pressure. w c o c g c F and c r The compressibility coefficients V of the aqueous phase, oil phase, gas phase, cracks, and matrix in the modified zone are respectively. F Let be the volume of the crack in the modified area.

[0118] The above formula (27) can be derived through the following process:

[0119] After well opening, as formation fluids are continuously extracted from the formation, formation pressure and reservoir fluid saturation are constantly changing. Therefore, calculations require continuous updates of the reservoir physical field during the production process based on the calculation step size. Formation pressure after well opening can still be calculated using the volume balance principle, i.e., the underground volume of extracted fluid equals the expansion of underground crude oil, the expansion of groundwater, the expansion of underground gas, and the decrease in pore volume.

[0120] V pro =ΔV o +ΔV w +ΔV p +ΔV g (28)

[0121] Among them, V pro =N p B o +Wp B w (29)

[0122] In formula (29), N p To achieve cumulative oil production after well opening, W p This refers to the cumulative water production after the well is opened.

[0123]

[0124] In formula (30), φ t The average oil saturation and porosity at different production stages, This represents the average pressure after well opening.

[0125]

[0126] In formula (31), This represents the average water saturation at different production stages.

[0127]

[0128] In formula (32), This represents the average gas saturation at different production stages.

[0129]

[0130] Substituting equations (29)-(33) into equation (28), we can obtain the average formation pressure at any time after well opening as follows:

[0131]

[0132] The carbon dioxide injection production capacity prediction method provided in Embodiment 1 of this invention starts from the injection injection mechanism, considers the energy replenishment and dissolution viscosity reduction mechanism of CO2 injection injection, divides the injection injection into the energy replenishment stage, the well-sealing dissolution viscosity reduction stage, and the well-opening recovery three-phase flow stage, and derives the pressure and saturation change equations for these three stages respectively, and derives the CO2 injection production capacity equation by combining the five-zone linear flow production capacity model of horizontal well volume fracturing.

[0133] Currently, the main software programs used for CO2 huff and puff research, such as large-scale commercial numerical simulation software like Intersect and Eclipse, employ numerical calculation methods. These software programs are expensive, have demanding operating environments, require large amounts of data, and involve lengthy research periods. The CO2 huff and puff production capacity prediction method provided in this invention targets unconventional oil reservoirs using CO2 huff and puff for energy supplementation. It employs analytical methods to evaluate well productivity, offering advantages over large-scale numerical simulation software, including greater specificity, lower cost, faster operation, and ease of use. It can evaluate the CO2 huff and puff productivity of different types of unconventional oil reservoirs, with a simple, fast, and efficient calculation method. This makes it more suitable for rapid evaluation and comparison of unconventional oil reservoir development methods and the formulation of development technology policies. Covering unconventional oil reservoir resources amounting to tens of billions of tons, it has broad application prospects.

[0134] Taking a typical well in the G test area as an example, the calculation results of the gas injection huff and puff method and the model analytical method (the model method in Example 1) are compared. The numerical simulation calculation uses the commonly used Eclipse numerical simulation software. The main parameters used in the model are shown in Table 1. The comparison results of the production and formation pressure of the gas injection huff and puff horizontal well are as follows. Figure 8 and Figure 9 As shown.

[0135] Table 1. Main parameters for the gas injection capacity prediction model validation.

[0136] Reservoir width, m 500 Cluster spacing, m 15 Reservoir thickness, m 12.5 Matrix permeability, mD 0.01 Crack permeability, mD 1000 <![CDATA[Rock compressibility, MPa -1 > <![CDATA[6e -4 ]]> matrix porosity 8％ Crack porosity 1％ Formation pressure, MPa 40 Crack half length, m 100 Number of fracturing sections and clusters 20 segments and 60 clusters Crude oil viscosity, mPa·s 10.0

[0137] The comparative schemes used both analytical and numerical simulation methods to calculate the production and formation pressure for three cycles of CO2 injection and huff-and-puff to replenish formation energy after horizontal volumetric fracturing and subsequent depletion production. After six years of depletion production following horizontal well volumetric fracturing, production was halted and replaced with injection. After one month of injection, 3,000 tons of CO2 were injected, followed by another month of well shut-down, and then 22 months of production before the next huff-and-puff cycle. This process was repeated for three cycles, injecting a total of 9,000 tons of CO2. Under the same operating conditions, the maximum production of the horizontal well gradually decreased. The comparison curves of production and formation pressure calculated by the numerical and analytical methods show that the results are similar, with an error within 5%. This demonstrates that the analytical model for injection and huff-and-puff in this embodiment has high accuracy in predicting development indicators and can be used for research on the evaluation of the development effect of volumetric fracturing and injection huff-and-puff in unconventional reservoirs, as well as for the formulation of development technology policies.

[0138] The above technical solutions are as follows Figure 10As shown, starting from the gas injection huff and puff mechanism, the energy replenishment mechanism and the dissolution and viscosity reduction mechanism of CO2 gas injection huff and puff are considered. In terms of physical process division, gas injection huff and puff is divided into the energy replenishment stage, the well-sealing dissolution and viscosity reduction stage, and the three-phase flow stage for well opening and recovery. The pressure and saturation change equations for these three stages are derived respectively. Considering the volumetric fracturing horizontal well as the main fracture zone, the modified zone, and the unmodified zone, the CO2 huff and puff production capacity equation is derived. Furthermore, based on the production capacity equation, the CO2 multi-round gas injection huff and puff recovery rate can be calculated, forming a rapid evaluation model for the development effect of CO2 gas injection huff and puff in the field, used for multiphase production capacity prediction and obtaining saturation data for each stage.

[0139] Example 2

[0140] This invention provides a specific implementation process for a method to predict the production capacity of CO2 injection for oil recovery. The model established in Example 1 is applied to the Lucao Gou Formation shale oil in the XX oilfield. The Lucao Gou Formation shale oil can be vertically divided into upper and lower sweet spots. The dominant lithology of the upper sweet spot is lithic feldspar fine-grained sandstone, while the dominant lithology of the lower sweet spot is dolomitic fine-grained siltstone. The lower sweet spot has a stable planar distribution, with a vertical reservoir thickness of 10–15 m, serving as the target layer in this study. The average permeability of the reservoir is 0.009 mD, and the crude oil viscosity at 50℃ ranges from 94.20 mPa·s to 407.08 mPa·s, with an average of 123.23 mPa·s. The formation crude oil viscosity ranges from 6 to 40 mPa·s, with an average of 21 mPa·s. To quickly evaluate the effect of CO2 injection for improving single-well production and recovery, the aforementioned production capacity equation software is used to predict the cumulative oil production of a single well under different CO2 injection rates. To assess recovery rate, four simulations with different injection volumes were designed. Each simulation involved three cycles of CO2 injection, with each cycle injecting 1000 tons, 2000 tons, 3000 tons, 4000 tons, and 5000 tons of CO2, respectively. The cumulative CO2 injections over the three cycles were 3000 tons, 6000 tons, 9000 tons, 12000 tons, and 15000 tons, respectively. The calculated cumulative oil production over 20 years for horizontal wells were 27715 cubic meters, 30936 cubic meters, 35383 cubic meters, 39903 cubic meters, and 42696 cubic meters, respectively. The production comparison curves are shown below. Figure 11The calculated recovery rates were 7.9%, 8.8%, 10.1%, 11.4%, and 12.2%, respectively, which were 0.3%, 1.2%, 2.5%, 3.8%, and 4.6% higher than those of depletion recovery. This shows that the higher the injection volume during CO2 huff and puff, the greater the increase in recovery rate. However, when the single-round CO2 huff and puff injection volume exceeds 4000 tons, the increase in horizontal well production and final recovery rate slows down under the same injection increment, resulting in relatively poorer economic benefits. The optimized single-round CO2 injection volume is 3000–4000 tons. Therefore, this method can effectively compare the production capacity of different CO2 huff and puff processes, predict the extent to which CO2 huff and puff improves recovery rate, and optimize development technology policies such as CO2 injection volume and injection rate. It provides an important research tool for the selection of CO2 huff and puff schemes and the determination of technical parameters.

[0141] Furthermore, this model is applicable to different types of tight oil and shale oil. The differences between various unconventional reservoirs mainly lie in the reservoir's main geological characteristic parameters, relative permeability curves, and CO2 dissolution equations. This patented analytical model can adjust the input data according to the specific parameters of each reservoir to obtain CO2 huff and puff predictions for each reservoir type, making it simple and efficient. Unconventional resources have become the mainstay of China National Petroleum Corporation's (CNPC) current and future production capacity construction. Horizontal well volumetric fracturing has become the main construction technology, but currently almost all horizontal wells adopt the depletion extraction method after volumetric fracturing, facing the problem of supplementing energy to improve recovery. CO2 huff and puff has proven to be an economical and effective way to supplement energy development, and this patent will provide a convenient and reliable analytical model for evaluating the production capacity of CO2 huff and puff in unconventional reservoirs, with broad application prospects.

[0142] Based on the inventive concept of this invention, embodiments of this invention also provide a carbon dioxide huff and puff extraction capacity prediction device, the structure of which is as follows: Figure 12 As shown, it includes:

[0143] The physical field update module 121 after carbon dioxide huff and puff injection is used to update the water content, oil content, gas content and formation pressure of the modified zone according to the carbon dioxide injection amount, fracture volume in the reservoir modified zone, volume of the modified zone, original formation pressure, water saturation, oil saturation and porosity after carbon dioxide huff and puff injection.

[0144] The physical field update module 122 for the stale well stage is used to perform the following steps at a first set interval during the stale well stage: determine the solubility of carbon dioxide in crude oil based on the current formation pressure and temperature; update the current water content, oil content and gas content saturation based on the solubility, the current oil saturation and the amount of carbon dioxide injected, until the end of the stale well stage; and determine the current crude oil viscosity based on the current solubility and oil saturation.

[0145] The physical field update and phase production prediction module 123 during the well opening production stage is used to perform the following steps at a second set interval: based on the current crude oil viscosity, carbon dioxide solubility in crude oil and the relative permeability of each phase under the current saturation conditions, the current production determined by the five-zone linear flow production model is multiphase split to obtain the production capacity of each phase, the cumulative production of each phase after well opening production is obtained, and the current water, oil and gas saturation is updated based on the cumulative production of each phase and the current oil saturation.

[0146] Regarding the apparatus in the above embodiments, the specific manner in which each module performs its operation has been described in detail in the embodiments related to the method, and will not be elaborated upon here.

[0147] Based on the inventive concept of the present invention, embodiments of the present invention also provide a computer program product, including a computer program / instruction, wherein the computer program / instruction, when executed by a processor, implements the above-mentioned carbon dioxide throughput mining capacity prediction method.

[0148] Unless otherwise specifically stated, terms such as processing, calculation, operation, determination, display, etc., may refer to the actions and / or processes of one or more processing or computing systems or similar devices that represent the manipulation and conversion of data representing physical (e.g., electronic) quantities within the registers or memory of the processing system into other data similarly representing physical quantities within the memory, registers, or other such information storage, transmission, or display devices of the processing system. Information and signals can be represented using any of a variety of different techniques and methods. For example, data, instructions, commands, information, signals, bits, symbols, and chips mentioned throughout the above description can be represented by voltage, current, electromagnetic waves, magnetic fields or particles, light fields or particles, or any combination thereof.

[0149] It should be understood that the specific order or hierarchy of steps in the disclosed process is an example of an exemplary method. Based on design preferences, it should be understood that the specific order or hierarchy of steps in the process may be rearranged without departing from the scope of this disclosure. The appended method claims provide elements of various steps in an exemplary order and are not intended to limit the scope to the specific order or hierarchy described.

[0150] In the detailed description above, various features are combined together in a single embodiment to simplify this disclosure. This approach to disclosure should not be construed as reflecting an intention that embodiments of the claimed subject matter require more features than are explicitly stated in each claim. Rather, as reflected in the appended claims, the invention is presented with fewer features than all of the features in a single disclosed embodiment. Therefore, the appended claims are hereby explicitly incorporated into the detailed description, with each claim representing a separate preferred embodiment of the invention.

[0151] Those skilled in the art will also understand that the various illustrative logic blocks, modules, circuits, and algorithm steps described in conjunction with the embodiments herein can be implemented as electronic hardware, computer software, or a combination thereof. To clearly illustrate the interchangeability between hardware and software, the various illustrative components, blocks, modules, circuits, and steps described above are generally described in terms of their functionality. Whether such functionality is implemented as hardware or software depends on the specific application and the design constraints imposed on the overall system. Those skilled in the art can implement the described functionality in alternative ways for each specific application; however, such implementation decisions should not be construed as departing from the scope of this disclosure.

[0152] The steps of the methods or algorithms described in conjunction with the embodiments herein can be directly embodied in hardware, software modules executed by a processor, or a combination thereof. The software modules can reside in RAM memory, flash memory, ROM memory, EPROM memory, EEPROM memory, registers, hard disks, removable disks, CD-ROMs, or any other form of storage medium well known in the art. An exemplary storage medium is connected to the processor, enabling the processor to read information from and write information to the storage medium. Of course, the storage medium can also be a component of the processor. The processor and storage medium can reside in an ASIC. The ASIC can reside in a user terminal. Alternatively, the processor and storage medium can exist as discrete components in the user terminal.

[0153] For software implementation, the techniques described in this application can be implemented using modules (e.g., procedures, functions, etc.) that perform the functions described in this application. This software code can be stored in memory units and executed by a processor. The memory units can be implemented within the processor or outside the processor; in the latter case, they are communicatively coupled to the processor via various means, as is well known in the art.

[0154] The foregoing description includes examples of one or more embodiments. It is certainly impossible to describe all possible combinations of components or methods in order to describe the above embodiments, but those skilled in the art will recognize that further combinations and arrangements of the various embodiments are possible. Therefore, the embodiments described herein are intended to cover all such changes, modifications, and variations that fall within the scope of the appended claims. Furthermore, the term "comprising" as used in the specification or claims is interpreted in a manner similar to the term "including," just as "including" is interpreted as a conjunction in the claims. Additionally, the use of any term "or" in the specification of the claims is intended to mean "non-exclusive or."

Claims

1. A method for predicting the production capacity of carbon dioxide injection and extraction, characterized in that, include: After carbon dioxide injection, the water, oil, and gas saturation and formation pressure of the modified zone are updated based on the carbon dioxide injection volume, fracture volume in the reservoir modification zone, volume of the modified zone, original formation pressure, water saturation, oil saturation, and porosity. During the well shut-in phase, the following steps are performed at the first set interval: the solubility of carbon dioxide in crude oil is determined based on the current formation pressure and temperature; the current water content, oil content and gas content saturation are updated based on the solubility, the current oil saturation and the amount of carbon dioxide injected, until the well shut-in phase ends; and the current crude oil viscosity is determined based on the current solubility and oil saturation. During the well opening and production phase, the following steps are performed at the second set interval: Based on the current crude oil viscosity, the solubility of carbon dioxide in crude oil, and the relative permeability of each phase under the current saturation conditions, the current production determined by the five-zone linear flow production capacity model is split into multiple phases to obtain the production capacity of each phase, and the cumulative production of each phase after well opening and production is obtained. Based on the cumulative production of each phase and the current oil saturation, the current water content, oil content, and gas content saturation are updated. The process of multiphase splitting the current output determined by the five-zone linear flow capacity model to obtain the capacity of each phase specifically includes: Based on the following formulas (1)-(3), the current production capacity determined by the five-zone linear flow production capacity model is divided into multiphase components to obtain the current production capacity of the aqueous phase, oil phase, and gas phase: (1)； (2)； (3)； In formulas (1)-(3), The current output determined by the five-zone linear flow capacity model; , and These represent the current production capacity of the aqueous phase, oil phase, and gas phase, respectively. , and These represent the relative permeabilities of the aqueous, oil, and gas phases under the current saturation conditions. Given the current crude oil viscosity, and The viscosity of the aqueous phase and the gas phase, respectively. , and These are the volume coefficients for the aqueous phase, oil phase, and gas phase, respectively. This represents the current solubility of carbon dioxide in crude oil. The process of updating the current water, oil, and gas saturations based on the cumulative yield of each phase and the current oil saturation specifically includes: Based on the cumulative yield of each phase and the current oil saturation, update the current water, oil, and gas saturations using the following formulas (4)-(6): (4)； (5)； (6)； In formulas (4)-(6), , and These are the updated water content, oil content, and gas saturation, respectively. The current oil saturation level, , and The cumulative yields for the aqueous phase, oil phase, and gas phase are respectively. , and These are the volume coefficients for the aqueous phase, oil phase, and gas phase, respectively. This represents the current solubility of carbon dioxide in crude oil. The volume of the modified area, The original porosity of the modified area, The ground volume of injected carbon dioxide. and These are the original water content and oil content of the modified area, respectively. , , and These refer to the original water content and oil saturation of the modified area, respectively.

2. The method as described in claim 1, characterized in that, After updating the current water, oil, and gas saturations based on the cumulative yield of each phase and the current oil saturation, the process further includes: The formation pressure is updated based on the cumulative production of each phase and the updated water, oil, and gas saturation.

3. The method as described in claim 2, characterized in that, The process of updating formation pressure based on the cumulative production of each phase and the updated water, oil, and gas saturation specifically includes: Based on the cumulative production of each phase and the updated water, oil, and gas saturation, the formation pressure is updated using the following formula (7): （7）； In formula (7), For the updated formation pressure, Given the current formation pressure, , , , and These are the compressibility coefficients of the aqueous phase, oil phase, gas phase, and the cracks and matrix in the modified zone, respectively. Let be the volume of the crack in the modified area.

4. The method as described in claim 1, characterized in that, The process of updating the water, oil, and gas saturation and formation pressure of the stimulated reservoir based on carbon dioxide injection volume, fracture volume in the stimulated reservoir, volume of the stimulated reservoir, original formation pressure, water saturation, oil saturation, and porosity specifically includes: Based on the volume of the modified area, the original water saturation, oil saturation, and porosity, the original water content and oil content of the modified area before carbon dioxide huff and puff injection are determined. Update the water, oil, and gas saturation of the modified area based on the amount of carbon dioxide injected and the original water and oil content of the modified area. The formation pressure of the modified zone is updated based on the amount of carbon dioxide injected, the volume of fractures in the modified zone, the volume of the modified zone, the original formation pressure, porosity, and the updated water, oil, and gas saturation.

5. The method as described in claim 4, characterized in that, Determining the original water content and oil content of the modified area before carbon dioxide huff and puff injection specifically includes: The original water content and oil content of the modified area before carbon dioxide huff and puff injection were determined by the following formulas (8) and (9): （8）； （9）； In formulas (8) and (9), and These are the original water content and oil content of the modified area, respectively. The volume of the modified area, The original porosity of the modified area, and These represent the original water content and oil saturation of the modified area, respectively. and These are the volume coefficients for the aqueous phase and the oil phase, respectively.

6. The method as described in claim 4, characterized in that, The step of updating the water content, oil content, and gas saturation of the modified area based on the carbon dioxide injection volume and the original water content and oil content of the modified area specifically includes: Based on the amount of carbon dioxide injected and the original water and oil content of the modified area, the water, oil, and gas saturation of the modified area are updated using the following formulas (10)-(12): （10）； （11）； （12）； In formula (10)-(12), , and These are the updated water content, oil content, and gas saturation, respectively. and These are the original water content and oil content of the modified area, respectively. , and These are the volume coefficients for the aqueous phase, oil phase, and gas phase, respectively. This refers to the ground volume injected with carbon dioxide.

7. The method as described in claim 4, characterized in that, The process of updating the formation pressure of the modified zone based on the carbon dioxide injection volume, fracture volume in the modified zone, volume of the modified zone, original formation pressure, porosity, and updated water, oil, and gas saturation specifically includes: Based on the carbon dioxide injection amount, the fracture volume in the modified zone, the volume of the modified zone, the original formation pressure, the porosity, and the updated water, oil, and gas saturation, the formation pressure of the modified zone is updated using the following formula (13): （13）； In formula (13), For the updated formation pressure, The original formation pressure of the modified area, , , , and These are the compressibility coefficients of the aqueous phase, oil phase, gas phase, and the cracks and matrix in the modified zone, respectively. , and These are the updated water content, oil content, and gas saturation, respectively. The volume of the modified area, The volume of the crack in the modified area. The original porosity of the modified area, is the volume coefficient of the gas phase.

8. The method as described in claim 1, characterized in that, The step of updating the current water, oil, and gas saturations based on the solubility, current oil saturation, and carbon dioxide injection amount specifically includes: Based on the solubility, the current oil saturation, and the amount of carbon dioxide injected, update the current water, oil, and gas saturations using formulas (14)-(16): （14）； （15）； （16）； In formulas (14)-(16), , and These are the updated water content, oil content, and gas saturation, respectively. and These are the original water content and oil content of the modified area, respectively. , , The volume of the modified area, The original porosity of the modified area, and These represent the original water content and oil saturation of the modified area, respectively. , and These are the volume coefficients for the aqueous phase, oil phase, and gas phase, respectively. The ground volume of injected carbon dioxide. The current oil saturation level, This represents the current solubility of carbon dioxide in crude oil.

9. The method as described in claim 1, characterized in that, The determination of the current crude oil viscosity based on the current solubility and oil saturation specifically includes: The mole fraction of carbon dioxide in crude oil is determined based on the current solubility and oil saturation. Determine the current viscosity of the crude oil based on the mole fraction of carbon dioxide in the crude oil and the current temperature.

10. The method as described in claim 9, characterized in that, The determination of the mole fraction of carbon dioxide in crude oil based on the current solubility and oil saturation specifically includes: Based on the current solubility and oil saturation, the mole fraction of carbon dioxide in crude oil is determined using the following formula (17): （17）； In formula (17), This represents the mole fraction of carbon dioxide in crude oil. This represents the current solubility of carbon dioxide in crude oil. The current oil saturation level, For the molar volume of the gas, The average molecular weight of crude oil. For crude oil density, The volume of the modified area, The original porosity of the modified area.

11. The method as described in claim 10, characterized in that, The determination of the current crude oil viscosity based on the mole fraction of carbon dioxide in the crude oil and the current temperature specifically includes: Based on the mole fraction of carbon dioxide in the crude oil and the current temperature, the current crude oil viscosity is determined using formula (18): （18）； In formula (18), Given the current crude oil viscosity, Here, T represents the mole fraction of carbon dioxide in the crude oil, and T is the current temperature. Let T be the viscosity of crude oil at temperature T in the absence of carbon dioxide. Let be the viscosity of carbon dioxide at the current temperature, and a and b be the influence coefficients.

12. The method according to any one of claims 1 to 11, characterized in that, Also includes: The reservoir after volumetric fracturing is divided into three regions: the main fracture zone, the modified zone, and the unmodified zone.

13. A carbon dioxide throughput production capacity prediction device, characterized in that, The apparatus is used to perform the method of claim 1, the apparatus comprising: The physical field update module after carbon dioxide huff and puff injection is used to update the water, oil and gas saturation and formation pressure of the modified zone based on the carbon dioxide injection amount, fracture volume in the reservoir modified zone, volume of the modified zone, original formation pressure, water saturation, oil saturation and porosity after carbon dioxide huff and puff injection. The physical field update module for the stalemate stage is used to perform the following steps at a first set interval during the stalemate stage: determine the solubility of carbon dioxide in crude oil based on the current formation pressure and temperature; update the current water content, oil content and gas content saturation based on the solubility, the current oil saturation and the amount of carbon dioxide injected, until the end of the stalemate stage; and determine the current crude oil viscosity based on the current solubility and oil saturation. The physical field update and phase production prediction module for the well opening production stage is used to perform the following steps at a second set interval during the well opening production stage: based on the current crude oil viscosity, the solubility of carbon dioxide in crude oil, and the relative permeability of each phase under the current saturation conditions, the current production determined by the five-zone linear flow production capacity model is split into multiple phases to obtain the production capacity of each phase, the cumulative production of each phase after well opening production is obtained, and the current water, oil and gas saturation is updated based on the cumulative production of each phase and the current oil saturation.

14. A computer program product comprising a computer program / instructions, characterized in that, When the computer program / instruction is executed by the processor, it implements the carbon dioxide throughput mining capacity prediction method according to any one of claims 1 to 12.

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