Method for optimizing size of pressure-driven pre-pad CO2 slug and method for drawing chart

Abstract

The application provides a method for optimizing the size of a pre-pressurized CO2 slug and a chart drawing method, and the method for optimizing the size of the pre-pressurized CO2 slug comprises the following steps: step 1, determining the CO2 characteristic content of a CO2-crude oil system; step 2, determining the relationship between the migration distance of the CO2 characteristic content front and the injection volume; step 3, determining the migration distance of the CO2 characteristic content front required for establishing displacement just between injection wells and production wells; and step 4, determining the injection volume of the pre-pressurized CO2 slug. The application can be used for scientifically designing the injection volume of the pre-pressurized CO2 slug in a low-permeability reservoir, guiding the preparation of a pressurized displacement scheme for the low-permeability reservoir, and can be used for conveniently optimizing the injection volume of the pre-pressurized CO2 slug, thereby providing technical support for the preparation of a pressurized displacement plan for the low-permeability reservoir.

Description

Technical Field

[0001] This invention relates to the field of pressure-driven enhanced oil recovery technology, and in particular to a method for optimizing the size of a CO2 slug before pressure-driven oil recovery and a method for drawing diagrams. Background Technology

[0002] Low-permeability reservoirs suffer from low water injection capacity or difficulty due to their low reservoir permeability. Shengli Oilfield has shifted its conventional water injection strategy for low-permeability reservoirs, moving from injection below fracturing pressure to injection above fracturing pressure. By using high-pressure water injection, the injection rate can be increased from 20m / s² to higher pressures. 3 / d increased to 1000-2000m 3 / d effectively solves the problem of difficult water injection in low-permeability reservoirs. This development method is defined as pressure drive.

[0003] During pressure drive practice, it was found that for ultra-low permeability reservoirs with a permeability of less than 10 mD, water can be injected into the formation, but due to the poor reservoir properties, the seepage resistance between injection and production wells is high, and the start-up pressure is also high, making it difficult for the injected fluid to seep effectively and for the pressure to be effectively transmitted. To address these issues, Shengli Oilfield proposed a method of injecting a certain amount of CO2 before pressure drive (pre-pressure drive CO2 slug) to reduce the seepage resistance and start-up pressure between injection and production wells, thereby achieving effective seepage of the injected fluid and effective transmission of pressure.

[0004] However, there is currently no mature method to refer to for determining the size of the CO2 slug in the pressure-driven pre-stage, and no method for determining it has been reported.

[0005] In Chinese patent application number CN201210384682.1, a method for determining the flow regime and optimizing parameters of a CO2-driven production well is disclosed, belonging to the field of oil reservoir development. The method includes the following steps: (1) Simulating the production dynamics of the CO2-driven production well to obtain the production dynamics of the CO2-driven production well and deriving the distribution patterns of injection wellbore pressure, temperature, density, and viscosity along the wellbore; (2) Plotting the distribution patterns of pressure and temperature along the wellbore obtained in step (1) on a CO2 phase diagram to obtain the pressure distribution diagram and temperature distribution diagram of the CO2 production wellbore, so that the CO2 phase state at different locations along the wellbore can be directly found in the diagram; (3) Optimizing production parameters: Under the premise of keeping the wellbore structure data unchanged, changing the production data, and then repeating steps (1) and (2), and optimizing the best production process and working system according to the field requirements. This invention realizes the simulation and analysis of the production dynamics of CO2-driven production wells.

[0006] Chinese patent application CN201410638170.2 discloses a method for determining the ultimate well spacing in CO2 flooding technology for low-permeability reservoirs. This method includes: determining the minimum miscibility pressure between CO2 and crude oil through long-tube displacement experiments; determining the relationship between the initiation pressure gradient and mobility under miscible and immiscible conditions through core displacement experiments combined with the minimum miscibility pressure of crude oil; establishing a formula for calculating the ultimate oil supply radius of CO2 flooding technology using reservoir engineering methods; obtaining the formation pressure distribution through field testing or reservoir numerical simulation methods, determining the miscible and immiscible regions, and calculating their proportional coefficients; and calculating the ultimate well spacing under current formation conditions using the formula for calculating the ultimate well spacing of CO2 flooding technology. This method for determining the ultimate well spacing in CO2 flooding technology for low-permeability reservoirs provides a basis for further tapping the potential of oilfields, increasing economically recoverable reserves, strengthening the resource base for development, and further improving crude oil recovery rates.

[0007] Chinese patent application CN201910561952.3 discloses a method for calculating the ultimate well spacing in CO2 miscible flooding of low-permeability reservoirs. This method includes: establishing a physical model of CO2 miscible flooding in low-permeability reservoirs by dividing the reservoir into three seepage zones—pure CO2 seepage zone, CO2 concentration decay zone, and pure oil seepage zone—based on changes in fluid properties during CO2 miscible flooding; establishing a mathematical model of CO2 miscible flooding in low-permeability reservoirs; solving the mathematical model of CO2 miscible flooding in low-permeability reservoirs sequentially according to the pure CO2 seepage zone, CO2 concentration decay zone, and pure oil zone; programming the key algorithms; and drawing a theoretical chart of CO2 miscible flooding in low-permeability reservoirs based on actual reservoir properties. This method calculates the ultimate well spacing based on the miscible front advancement distance and the pressure sweep range of the production well, considering factors such as miscible seepage resistance, expected production, and changes in fluid properties. The calculation model is closer to the actual reservoir properties, and the calculation results are more reliable, providing guidance for CO2 miscible flooding development in low-permeability reservoirs.

[0008] The above-mentioned existing technologies are all quite different from the present invention and have failed to solve the technical problem we want to solve. Therefore, we have invented a new method for optimizing the size of the pressure-driven pre-CO2 slug and a method for drawing the diagram. Summary of the Invention

[0009] The purpose of this invention is to provide a method for optimizing the size of the CO2 slug in the pressure drive process and a method for drawing diagrams that enables effective pressure transmission during pressure drive.

[0010] The objective of this invention can be achieved through the following technical measures: a method for optimizing the size of the CO2 slug before pressure drive, which includes:

[0011] Step 1: Determine the characteristic CO2 content of the CO2-crude oil system;

[0012] Step 2: Determine the relationship between the CO2 characteristic content frontal migration distance and the injection volume;

[0013] Step 3: Determine the distance between injection and production wells that is just enough to establish the CO2 characteristic content front migration required for displacement;

[0014] Step 4: Determine the injection volume of CO2 before pressure drive.

[0015] The objective of this invention can also be achieved through the following technical measures:

[0016] In step 1, the characteristic CO2 content of the CO2-crude oil system is the molar CO2 content in the CO2-crude oil system. When the molar CO2 content of the CO2-crude oil system is higher than the characteristic CO2 content, the system properties are closer to those of CO2, which can reduce seepage resistance, improve flow capacity, and the nonlinear seepage characteristics gradually disappear, that is, the starting pressure approaches zero.

[0017] In step 1, the CO2 characteristic content of the CO2-crude oil system corresponding to the disappearance of nonlinear seepage characteristics is determined by seepage experiments on CO2-crude oil systems with different CO2 contents.

[0018] In step 2, the CO2 characteristic content front is the physical location where the CO2 characteristic content is located; as CO2 is continuously injected into the injection well, the CO2 characteristic content front expands outward with the increase of the injection volume.

[0019] In step 2, the relationship between the CO2 characteristic content front migration distance and the injection volume is determined through numerical simulation and reservoir engineering methods.

[0020] In step 3, the establishment of displacement between injection and production wells refers to the pressure drop in seepage resistance and the pressure drop in initiation pressure between the injection and production wells at a certain pressure-driven injection rate. O The sum is exactly equal to the applied injection-production pressure difference ΔP; the pressure drop due to seepage resistance between injection and production wells includes the CO2 phase pressure drop ΔP. CO2 With oil phase pressure drop ΔP O The formula for calculating the injection-production pressure difference ΔP is as follows:

[0021] ΔP=ΔP CO2 +ΔP O +G O (Equation 1).

[0022] In step 3, the distance that the injection and production wells must travel to establish the CO2 characteristic content front required for displacement is the well spacing L occupied by the CO2 phase. CO2 The well spacing L occupied by the oil phaseO Equals injection-production well spacing L minus the well spacing L occupied by the CO2 phase. CO2 The injection-production well spacing should be the matrix well spacing after removing the influence of fracturing fractures; the well spacing L occupied by the oil phase. O The calculation formula is as follows:

[0023] L O =LL CO2 (Equation 2).

[0024] In step 3, three regions exist between injection and production wells: the CO2 phase, the CO2-crude oil system, and the oil phase. For miscible flooding, the viscosity of the fluid in the CO2-crude oil system changes continuously and monotonically with distance, and the CO2 characteristic content is close to 50%. Therefore, for simplification in engineering calculations, the CO2 phase and oil phase are considered in the seepage resistance calculation. The pressure drop of the CO2 phase and the pressure drop of the oil phase are determined by Darcy's law. The pressure drop of the CO2 phase is a function of the well distance occupied by the CO2 phase and the reservoir permeability K, i.e., Equation 3. The pressure drop of the oil phase is a function of the well distance occupied by the oil phase, the reservoir permeability K, and the oil phase viscosity μ. O The function is Equation 4:

[0025] ΔP CO2 =f(L CO2 ,K,) (Equation 3)

[0026] ΔP O =f(L O ,K,μ O (Equation 4).

[0027] In step 3, the starting pressure drop is determined based on laboratory tests or empirical formulas. For low-permeability reservoirs, the starting pressure drop is described by Equation 5, derived from the empirical formula for starting pressure, where K is the gas permeability (mD); μ O Oil phase viscosity, mPa·s:

[0028]

[0029] In step 4, the injection amount of CO2 before pressure drive is determined by the distance between the injection and production wells that can just establish the displacement of the CO2 characteristic content front migration distance, i.e., the well distance occupied by the CO2 phase, as determined in step 3, and then combined with the relationship between the CO2 characteristic content front migration distance and the injection amount determined in step 2.

[0030] The objective of this invention can also be achieved through the following technical measures: a method for drawing the dimensions of the CO2 slug before the pressure drive, the method comprising:

[0031] Step 5: Determine a series of mobility values ​​for calculation based on the parameter range of the relevant reservoir properties;

[0032] Step 6: Calculate the CO2 injection rate for different flow rates and injection-production well spacings using the CO2 slug size optimization method before pressure drive.

[0033] Step 7: Convert the CO2 injection volume into the HCPV number or PV number of the injected reservoir, which is used to describe the slug size;

[0034] Step 8: Draw the calculation diagram for the CO2 slug size of the pressure drive pre-stage.

[0035] The objective of this invention can also be achieved through the following technical measures:

[0036] In step 5, the mobility is the ratio of reservoir permeability to formation crude oil viscosity.

[0037] Step 6 includes:

[0038] Step 61: Determine the characteristic CO2 content of the CO2-crude oil system;

[0039] Step 62: Determine the relationship between the CO2 characteristic content frontal migration distance and the injection volume;

[0040] Step 63: Determine the distance between the injection and production wells that is just enough to establish the CO2 characteristic content front migration required for displacement;

[0041] Step 64: Determine the injection volume of CO2 before pressure drive.

[0042] In step 7, the HCPV number injected into the reservoir is a multiple of the injected fluid occupying the hydrocarbon pore volume, defined as the ratio of the injected CO2 volume to the pore volume occupied by the crude oil in the original reservoir under reservoir conditions.

[0043] In step 7, the PV number injected into the reservoir is the multiple of the injected fluid to the reservoir pore volume, defined as the ratio of the injected CO2 volume to the original reservoir pore volume under reservoir conditions.

[0044] In step 8, the calculation chart for the CO2 slug size before pressure drive is a curve showing the relationship between different flow rates, with the injection-production well distance as the horizontal axis and the HCPV number or PV number corresponding to the CO2 injection volume as the vertical axis.

[0045] The method for optimizing the size of the CO2 slug before pressure drive in this invention can be used to guide the development of enhanced oil recovery through pressure drive in ultra-low permeability reservoirs, and can be used for the scientific design of the injection volume of the CO2 slug before pressure drive in low permeability reservoirs, guiding the preparation of pressure drive schemes for low permeability reservoirs. The method for drawing diagrams of the CO2 slug size before pressure drive provided by this invention can be used to conveniently optimize the injection volume of the CO2 slug before pressure drive, providing technical support for the planning and preparation of pressure drive programs for low permeability reservoirs. Attached Figure Description

[0046] Figure 1 A schematic diagram illustrating the effect of different CO2 quantities on the pressure distribution between injection and production wells;

[0047] Figure 2 This is a flowchart of a specific embodiment of the method for optimizing the size of the pre-CO2 slug in the pressure-driven system of the present invention;

[0048] Figure 3 This is a flowchart of a specific embodiment of the method for drawing the dimensions of the pre-pressure CO2 slug in a specific embodiment of the present invention;

[0049] Figure 4 This is a diagram showing the calculation of the dimensions of the pre-pressure CO2 slug in a specific embodiment of the present invention. Detailed Implementation

[0050] It should be noted that the following detailed descriptions are exemplary and intended to provide further illustration of the invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0051] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments of the present invention. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, and / or combinations thereof.

[0052] In the process of pressure drive development, in response to the problem that fluids are difficult to effectively flow and pressure is difficult to effectively transmit after pressure drive in ultra-low permeability reservoirs, a method of injecting a certain amount of CO2 before pressure drive is proposed to reduce the seepage resistance and start-up pressure between injection and production wells, so as to achieve effective seepage of the injected fluid and effective transmission of pressure. The specific reasons are analyzed as follows.

[0053] CO2 has low viscosity in formations (0.04 mPa·s, one-tenth the viscosity of water), resulting in low flow resistance. For the same well spacing, CO2 flooding has a lower displacement pressure differential than water flooding. CO2 flow in low-permeability reservoirs exhibits minimal nonlinear flow characteristics, and the initiation pressure is negligible (preliminary verification has been achieved through laboratory experiments). CO2 slug flow in low-permeability reservoirs does not require overcoming additional resistance (unlike water slugs which require overcoming initiation pressure). Pre-positioning CO2 slugs in pressure flooding can effectively reduce flow resistance between injection and production wells (see...). Figure 1 On the one hand, the pressure differential required for CO2 slug seepage (displacement pressure drop) is significantly reduced; on the other hand, the initiation pressure within the CO2 slug is negligible. The pre-positioned CO2 slug reduces the seepage resistance between injection and production wells, allowing for effective displacement during subsequent pressure-driven water injection, thus improving fluid seepage capacity and pressure transmission capacity. Figure 1 It can also be seen that the larger the CO2 slug size, the smaller the required displacement pressure difference, and the more significant the improvement in fluid permeability.

[0054] The method for optimizing the size of the pressure-driven pre-CO2 slug of the present invention includes the following steps:

[0055] Step 1: Determine the characteristic CO2 content of the CO2-crude oil system;

[0056] The characteristic CO2 content of the CO2-crude oil system refers to the molar CO2 content within the system. When the CO2 content of the CO2-crude oil system exceeds the characteristic CO2 content, the system properties become closer to those of the CO2 phase, significantly reducing seepage resistance and improving flow capacity. More importantly, the nonlinear seepage characteristics gradually disappear, meaning the starting pressure approaches zero.

[0057] The CO2 characteristic content of the CO2-crude oil system corresponding to the disappearance of nonlinear seepage characteristics can be determined by seepage experiments on CO2-crude oil systems with different CO2 contents.

[0058] Step 2: Determine the relationship between the CO2 characteristic content frontal migration distance and the injection volume;

[0059] The CO2 characteristic content front is the physical location where the CO2 characteristic content is located; as CO2 is continuously injected into the injection well, the CO2 characteristic content front expands outward with the increase of the injection volume.

[0060] The relationship between the migration distance of the CO2 characteristic content front and the injection volume can be determined through numerical simulation and reservoir engineering methods.

[0061] Step 3: Determine the distance between injection and production wells that is just enough to establish the CO2 characteristic content front migration required for displacement;

[0062] The point at which displacement can be established between injection and production wells refers to the pressure drop in seepage resistance and the pressure drop in initiation pressure between the two wells at a certain pressure-driven injection rate. O The sum is exactly equal to the applied injection-production pressure difference ΔP (see Equation 1). The pressure drop due to seepage resistance between injection and production wells includes the CO2 phase pressure drop ΔP. CO2 With oil phase pressure drop ΔP O The pressure drop in the CO2 phase and the pressure drop in the oil phase can be determined using the following methods, or other methods.

[0063] ΔP=ΔP CO2 +ΔP O +G O (Equation 1)

[0064] The distance L between injection and production wells that allows the CO2 characteristic content front to be established for displacement is the well spacing L occupied by the CO2 phase. CO2 The well spacing L occupied by the oil phase O It equals the injection-production well distance L minus the well distance occupied by the CO2 phase (Equation 2). The injection-production well distance should be the matrix well distance after removing the influence of fracturing fractures.

[0065] L O =LL CO2 (Equation 2)

[0066] Between injection and production wells, there are three regions: the CO2 phase, the CO2-crude oil system, and the oil phase. For miscible flooding, the viscosity of the fluid in the CO2-crude oil system changes continuously and monotonically (with distance), and the characteristic CO2 content is generally close to 50%. Therefore, for simplification in engineering calculations, the seepage resistance (pressure drop) is calculated considering both the CO2 and oil phases. The pressure drop of the CO2 phase and the oil phase can be determined using Darcy's law. The CO2 phase pressure drop is a function of the well distance occupied by the CO2 phase and the reservoir permeability K (Equation 3), while the oil phase pressure drop is a function of the well distance occupied by the oil phase, the reservoir permeability K, and the oil phase viscosity μ. O The function (Equation 4).

[0067] ΔP CO2 =f(L CO2 ,K,) (Equation 3)

[0068] ΔP O =f(L O ,K,μ O (Equation 4)

[0069] The starting pressure drop can be determined based on laboratory tests or empirical formulas. For low-permeability reservoirs in Shengli Oilfield, the starting pressure drop can be described by Equation 5, derived from the empirical formula for starting pressure, where K is the gas permeability (mD); μO ρ represents the oil phase viscosity, in mPa·s.

[0070]

[0071] Step 4: Determine the injection volume of CO2 before pressure drive.

[0072] The injection volume of CO2 before pressure drive can be determined by the distance between the injection and production wells determined in step 3, which is just enough to establish the migration distance of the CO2 characteristic content front (the well distance occupied by the CO2 phase), and then combined with the relationship between the CO2 characteristic content front migration distance and the injection volume determined in step 2.

[0073] This invention proposes a method for plotting the dimensions of a CO2 slug before pressure drive, which can be used to determine the dimensions of a CO2 slug before pressure drive in reservoirs with similar distances (same depression) and properties (permeability, crude oil viscosity). This can be achieved through the following technical measures based on the above steps:

[0074] Step 5: Determine a series of mobility values ​​for calculation based on the parameter range of relevant reservoir properties; mobility is the ratio of reservoir permeability (gas measurement) to formation crude oil viscosity.

[0075] Step 6: Calculate the CO2 injection rate before pressure drive for different mobility and injection-production well spacings; calculate the CO2 injection rate before pressure drive for different mobility and injection-production well spacings using the methods provided in Steps 1-4.

[0076] Step 7: Convert the CO2 injection volume into the HCPV number or PV number of the injected reservoir, which is used to describe the slug size; the HCPV number of the injected reservoir is the multiple of the injected fluid to the hydrocarbon pore volume, and is defined as the ratio of the injected CO2 volume to the pore volume occupied by the crude oil in the original reservoir under reservoir conditions.

[0077] The PV number injected into the reservoir is the multiple of the injected fluid to the reservoir pore volume, and is defined as the ratio of the injected CO2 volume to the original reservoir pore volume under reservoir conditions.

[0078] Step 8: Draw the calculation diagram for the CO2 slug size of the pressure drive pre-stage.

[0079] The chart for calculating the size of the CO2 slug before pressure drive is a curve showing the relationship between different flow rates, with the injection-production well distance as the horizontal axis and the size of the CO2 slug (HCPV number or PV number corresponding to the CO2 injection volume) as the vertical axis.

[0080] The following are several specific embodiments of the application of the present invention.

[0081] Example 1

[0082] In a specific embodiment 1 of the present invention, such as Figure 2 As shown, Figure 2 This is a flowchart of a specific embodiment of the method for optimizing the injection volume of the pre-pressure CO2 slug of the present invention.

[0083] In step 101, combining indoor experiments and statistical regression analysis, the CO2 characteristic content of the crude oil and CO2 system in Block A of Shengli Oilfield was determined to be 53%.

[0084] The process proceeds to step 102.

[0085] In step 102, the distribution law of the component front at different injection amounts during the CO2 flooding process was studied by numerical simulation method. Then, the front migration law when the CO2 component content is 53% was found, which is the relationship between the front migration distance of CO2 characteristic content and the injection amount.

[0086] The process proceeds to step 103.

[0087] In step 103, the greater the distance occupied by the CO2 phase in the injection-production well spacing, the smaller the seepage resistance between the injection and production wells, and the easier it is to establish effective displacement. The distance that the CO2 characteristic content front should migrate refers to the distance occupied by the CO2 phase that can just establish effective displacement under the current injection-production pressure difference and injection-production well spacing (the distance of CO2 characteristic content front migration).

[0088] For Block A, the geological reserves are 370,000 tons, the reservoir porosity is 0.2, the permeability is 6 mD, the oil layer thickness is 10 m, the underground crude oil viscosity is 2 mPa·s, the well configuration is 1 injection and 4 production wells, the injection-production well spacing is 300 m, and pressure-driven water injection will be carried out in Block A at an injection rate of 600 m / s. 3 / d. Based on seepage theory calculations, when the CO2 characteristic content (53% composition) front migrates to 108m, the calculated oil phase initiation pressure is 33.3MPa, the CO2 phase seepage resistance is 1.7MPa, and the oil phase seepage resistance is 14.8MPa, totaling 49.8MPa. Considering an injection-production pressure difference of 50MPa, effective displacement can be established at this point. Therefore, the CO2 characteristic content front should migrate a distance of 108m.

[0089] The process proceeds to step 104.

[0090] In step 104, based on the relationship between the leading edge migration distance of CO2 characteristic content and the injection amount obtained in step 102, and based on the fact that the leading edge migration distance of CO2 characteristic content is 108m obtained in step 103, the injection amount of CO2 at this time can be determined.

[0091] Example 2

[0092] In a specific embodiment 2 of the present invention, such asFigure 3 As shown, Figure 3 This is a flowchart of a specific embodiment of the pressure-driven pre-CO2 slug slug size calculation diagram of the present invention.

[0093] In step 105, based on the geological characteristics of the reservoirs surrounding Block A, a series of mobility values ​​for calculation are determined: 1-10.

[0094] The process proceeds to step 106.

[0095] In step 106, the CO2 injection rate before pressure drive is calculated based on steps 101-104 for different well spacings and different flow rates.

[0096] The process proceeds to step 107.

[0097] In step 107, the CO2 injection amount calculated in step 106 is converted into HCPV number.

[0098] The process proceeds to step 108.

[0099] In step 108, a curve is plotted with the injection-production well spacing as the abscissa and the front CO2 slug size (HCPV number corresponding to CO2 injection rate) as the ordinate, showing the relationship under different mobility conditions, as follows: Figure 4 As shown.

[0100] Example 3

[0101] In a specific embodiment 3 of the present invention, such as Figure 2 As shown, Figure 2 This is a flowchart of a specific embodiment of the method for optimizing the injection volume of the pre-pressure CO2 slug of the present invention.

[0102] In step 101, combining indoor experiments and statistical regression data, the CO2 characteristic content of the crude oil and CO2 system in Block B of Shengli Oilfield was determined to be 55%.

[0103] The process proceeds to step 102.

[0104] In step 102, the relationship between the frontal migration distance of CO2 characteristic content and the injection amount was studied by numerical simulation.

[0105] The process proceeds to step 103.

[0106] In step 103, for block B, the geological reserves are 430,000 tons, the reservoir porosity is 0.18, the permeability is 2mD, the oil layer thickness is 9m, the underground crude oil viscosity is 1mPa·s, and there is one injection and four production wells with a well spacing of 350m. Pressure-driven water injection is performed on block B at an injection rate of 400m / s. 3 / d. Based on seepage theory calculations, when the CO2 characteristic content (55% composition) front migrates to 223m, the calculated oil phase initiation pressure is 31.6MPa, the CO2 phase seepage resistance is 7.6MPa, and the oil phase seepage resistance is 10.9MPa, totaling 50MPa. Considering the injection-production pressure difference of 50MPa, effective displacement can be established at this point. Therefore, the CO2 characteristic content front should migrate a distance of 223m.

[0107] The process proceeds to step 104.

[0108] In step 104, based on the CO2 characteristic content front migration distance obtained in step 103 as 223m, it can be determined that the CO2 injection amount at this time is 0.035HCPV. Based on the geological reserves, the underground crude oil volume is calculated to be 468,000 cubic meters. It is calculated that 16,000 tons of CO2 should be injected before the pressure drive of block B to achieve effective transmission of injection and production pressure.

[0109] Finally, it should be noted that the above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

[0110] Except for the technical features described in the specification, all other technologies are known to those skilled in the art.

Claims

1. A method for optimizing the size of a pre-pressure driven CO2 slug, characterized in that, The method for optimizing the size of the CO2 slug in the pre-drive pressure drive includes: Step 1: Determine the characteristic CO2 content of the CO2-crude oil system; The characteristic CO2 content of the CO2-crude oil system is the molar CO2 content in the CO2-crude oil system. When the molar CO2 content of the CO2 in the CO2-crude oil system is higher than the characteristic CO2 content, the system properties are closer to those of CO2, which can reduce seepage resistance, improve flow capacity, and the nonlinear seepage characteristics gradually disappear, that is, the starting pressure approaches zero. Step 2: Determine the relationship between the CO2 characteristic content frontal migration distance and the injection volume; Step 3: Determine the distance between injection and production wells that is just enough to establish the CO2 characteristic content front migration required for displacement; The point at which displacement can be established between injection and production wells refers to the pressure drop in seepage resistance and the pressure drop at startup between the two wells at a certain pressure-driven injection rate. The sum is exactly equal to the applied injection-production pressure difference. The pressure drop in seepage resistance between injection and production wells includes the pressure drop in the CO2 phase. Oil phase pressure drop Injection-production pressure difference The calculation formula is as follows: (Equation 1); The distance between injection and production wells that allows the CO2 characteristic content front to be established for displacement is the well spacing occupied by the CO2 phase. The well spacing occupied by the oil phase equal to the distance between injection and production wells Subtract the well spacing occupied by the CO2 phase The injection-production well spacing should be the matrix well spacing after removing the influence of fracturing fractures; the well spacing occupied by the oil phase. The calculation formula is as follows: (Equation 2); Between injection and production wells, there are three regions: the CO2 phase, the CO2-crude oil system, and the oil phase. The pressure drop in the CO2 phase and the oil phase are determined using Darcy's law. The CO2 phase pressure drop is a function of the well spacing occupied by the CO2 phase and the reservoir permeability K, i.e., Equation 3. The oil phase pressure drop is a function of the well spacing occupied by the oil phase, the reservoir permeability K, and the oil phase viscosity μ. O The function is Equation 4: (Equation 3); (Equation 4); Step 4: Determine the injection volume of CO2 before pressure drive; The injection volume of CO2 before pressure drive is determined by the distance between the injection and production wells determined in step 3, which is just enough to establish the migration distance of the CO2 characteristic content front, i.e. the well spacing occupied by the CO2 phase. This is combined with the relationship between the CO2 characteristic content front migration distance and the injection volume determined in step 2.

2. The method for optimizing the size of the pre-CO2 slug in a pressure-driven system according to claim 1, characterized in that, In step 1, the CO2 characteristic content of the CO2-crude oil system corresponding to the disappearance of nonlinear seepage characteristics is determined by seepage experiments on CO2-crude oil systems with different CO2 contents.

3. The method for optimizing the size of the pre-CO2 slug in a pressure-driven system according to claim 1, characterized in that, In step 2, the CO2 characteristic content front is the physical location where the CO2 characteristic content is located; as CO2 is continuously injected into the injection well, the CO2 characteristic content front expands outward with the increase of the injection volume.

4. The method for optimizing the size of the pre-CO2 slug in a pressure-driven system according to claim 3, characterized in that, In step 2, the relationship between the CO2 characteristic content front migration distance and the injection volume is determined through numerical simulation and reservoir engineering methods.

5. The method for optimizing the size of the pre-CO2 slug in a pressure-driven system according to claim 1, characterized in that, In step 3, the starting pressure drop is determined based on laboratory tests or empirical formulas. For low-permeability reservoirs, the starting pressure drop is described by Equation 5, derived from the empirical formula for starting pressure. For gas permeability, mD; Oil phase viscosity, mPa·s; Start-up pressure, MPa; The distance between injection and production wells occupied by the oil phase, in cm: (Equation 5).

6. A method for drawing the dimensions of a pre-pressure CO2 slug, characterized in that, The method for drawing the dimensions of the CO2 slug in front of the pressure drive adopts the method for optimizing the dimensions of the CO2 slug in front of the pressure drive as described in claim 1, including: Step 5: Determine a series of mobility values ​​for calculation based on the parameter range of relevant reservoir properties; mobility is the ratio of reservoir permeability to formation crude oil viscosity. Step 6: Calculate the CO2 injection rate for different flow rates and injection-production well spacings using the CO2 slug size optimization method before pressure drive. Step 7: Convert the CO2 injection volume into the HCPV number or PV number of the injected reservoir, which is used to describe the slug size; Step 8: Draw the calculation diagram for the CO2 slug size of the pressure drive pre-stage; The calculation chart for the CO2 slug size before pressure drive uses the injection-production well distance as the horizontal axis and the HCPV number or PV number corresponding to the CO2 injection volume as the vertical axis, showing the relationship curves under different flow rates.

7. The method for drawing the dimensions of the pre-CO2 slug in a pressure-driven system according to claim 6, characterized in that, Step 6 includes: Step 61: Determine the characteristic CO2 content of the CO2-crude oil system; Step 62: Determine the relationship between the CO2 characteristic content frontal migration distance and the injection volume; Step 63: Determine the distance between the injection and production wells that is just enough to establish the CO2 characteristic content front migration required for displacement; Step 64: Determine the injection volume of CO2 before pressure drive.

8. The method for drawing the dimensions of the pre-CO2 slug in a pressure-driven system according to claim 6, characterized in that, In step 7, the HCPV number injected into the reservoir is a multiple of the injected fluid occupying the pore volume of hydrocarbons, defined as the ratio of the injected CO2 volume to the pore volume occupied by the crude oil in the original reservoir under reservoir conditions.

9. The method for drawing the dimensions of the pre-CO2 slug in a pressure-driven system according to claim 6, characterized in that, In step 7, the PV number injected into the reservoir is the multiple of the injected fluid to the reservoir pore volume, defined as the ratio of the injected CO2 volume to the original reservoir pore volume under reservoir conditions.

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