Method for calculating initial injection capacity of CO2 flooding in low-permeability oil reservoirs

Abstract

The application provides a low-permeability oil reservoir CO2 flooding initial injection capacity calculation method, which comprises the following steps: step 1, calculating the initial gas absorption index of a target block; step 2, calculating the start-up pressure gradient of an implemented block; step 3, calculating the relative start-up pressure gradient of the target block; step 4, calculating the gas injection pressure difference of the target block; step 5, determining the sand body thickness of the target block; and step 6, calculating the CO2 flooding initial injection capacity of the target block according to a CO2 injection capacity calculation formula. The low-permeability oil reservoir CO2 flooding initial injection capacity calculation method can provide a key technical policy determination method for low-permeability oil reservoir CO2 flooding reservoir engineering scheme compilation and guide the CO2 flooding reservoir engineering scheme compilation.

Description

Technical Field

[0001] The present invention relates to the technical field of CO2 flooding to enhance oil recovery, and in particular to a method for calculating the initial injection capacity of CO2 flooding in low-permeability oil reservoirs. Background Art

[0002] Low-permeability reservoirs are abundant in China and have become a key focus for increasing reserves and production in oil development. However, efficient development of low-permeability reservoirs is challenging. Ultra-low permeability reservoirs with permeabilities less than 10 mD experience low elastic recovery rates and are difficult to inject into water. Low-permeability reservoirs with permeabilities between 10 and 30 mD have low water injection capacity and low oil production rates. Low-permeability reservoirs with permeabilities between 30 and 50 mD have generally entered a medium-to-high water-cut phase, resulting in low single-well productivity and recovery rates. Supercritical CO₂, due to its low viscosity and strong miscibility with crude oil, can significantly improve the injection capacity and recovery of low-permeability reservoirs.

[0003] When developing a CO2 flooding reservoir engineering plan, determining CO2 injectivity is fundamental to predicting CO2 flooding development indicators, but this is often difficult to determine. For conventional low-permeability reservoirs, the injectivity increases with continued CO2 injection. Low-permeability reservoirs that can achieve effective injection initially will not have injection issues in the middle and later stages. Therefore, determining the initial CO2 flooding injectivity is often crucial for reservoir engineering calculations.

[0004] Current methods for calculating the initial injectivity of CO2 flooding include reservoir engineering calculations and numerical simulations. While these methods are numerous, most are based on theoretical models, resulting in significant errors compared to field realities. Numerical simulations must rely on history matching to achieve reliable results, making them less suitable for areas with a short development history.

[0005] The Chinese patent application with application number CN201910709775.9 relates to a method and apparatus for determining injectivity during alternating water-gas injection. The method comprises: within each preset interval, determining whether each fluid is in the roar channel based on the geometry of the capillary and the equivalent length of the currently selected fluid; and then determining the injection volume of carbon dioxide or water within the current interval based on the geometry of the capillary, the pressure difference across the capillary, and the value of a preset parameter; determining the ratio of the injection volume to the pressure difference as the injectivity of the capillary within the current interval; and determining the carbon dioxide flow rate based on the injection volume. Furthermore, determining the equivalent length of the miscible zone and the equivalent length of carbon dioxide based on the relationship between the equivalent length of the miscible zone and the carbon dioxide flow time and flow rate, to determine whether the fluid is in the roar channel at the start of the next interval. This method can quantify the injectivity during alternating water-gas injection at a microscopic scale, providing a theoretical basis for studying the changing patterns and influencing factors of reservoir injectivity.

[0006] The Chinese patent application, filed with application number CN201910561065.6, describes an experimental apparatus and method for alternating CO2 microbubble flooding in heavy oil reservoirs using a hybrid nanofluid. This apparatus incorporates hybrid nanoparticles and, combined with the advantages of CO2 microbubbles, uses alternating injection to effectively suppress gas channeling and gravity overburden during conventional CO2 gas-water alternating flooding in heavy oil reservoirs, thereby improving the recovery rate of these reservoirs. Compared to CO2 gas, CO2 microbubbles have stronger solubility and diffusion capabilities in crude oil and lower buoyancy, effectively reducing the viscosity of heavy oil, expanding its volume, and improving its sweep efficiency. Hybrid nanofluids, by combining the advantages of various nanoparticles, can alter the wettability of reservoir rock, reduce oil-water interfacial tension, and improve oil washing efficiency. Furthermore, the invention employs a method of injecting a hybrid nanofluid slug in the upper reservoir and a CO2 microbubble slug in the lower reservoir, helping to suppress gas channeling and gravity overburden and improving the vertical sweep efficiency.

[0007] The Chinese patent application with application number CN201910812302.1 involves a CO2 flooding composite development method for low-permeability thick-layer sandstone reservoirs. The CO2 flooding composite development method for low-permeability thick-layer sandstone reservoirs includes: step 1, selecting the reservoir to be developed; step 2, performing the CO2 huff-and-puff stage; step 3, performing the gas cap formation stage; step 4, performing the injection-production coupling stage; and step 5, performing the flooding composite stage. This invention adjusts the development method with unsatisfactory development effects in the later stage of CO2 flooding from the perspective of mitigating CO2 flooding gas overburden. By utilizing the stable gas cap between the injection and production wells and the gravity of the crude oil itself, the problem of difficulty in mobilizing the bottom crude oil caused by the gas overburden effect can be effectively mitigated, thereby achieving efficient and stable development of closed boundary reservoirs in the later stage of CO2 flooding.

[0008] The above existing technologies are significantly different from the present invention and fail to solve the technical problem we want to solve. Therefore, we have invented a new method for calculating the initial injection capacity of CO2 flooding in low permeability reservoirs. Summary of the Invention

[0009] The purpose of the present invention is to provide a method for determining key technical policies for the preparation of CO2 flooding reservoir engineering plans for low permeability reservoirs, and a method for calculating the initial injection capacity of CO2 flooding in low permeability reservoirs to guide the preparation of CO2 flooding reservoir engineering plans.

[0010] The object of the present invention can be achieved by the following technical measures: a method for calculating the initial injection capacity of CO2 flooding in low permeability reservoirs, the method comprising:

[0011] Step 1, calculate the initial rice aspiration index of the target block;

[0012] Step 2: Calculate the starting pressure gradient of the implemented block;

[0013] Step 3, calculating the relative starting pressure gradient of the target block;

[0014] Step 4, calculating the gas injection pressure difference of the target block;

[0015] Step 5, determining the sand body thickness of the target block;

[0016] Step 6: Calculate the initial CO2 injection capacity of the target block according to the CO2 injection capacity calculation formula.

[0017] The purpose of the present invention can also be achieved by the following technical measures:

[0018] In step 1, according to the gas absorption index multiple β and the initial water-free rice oil recovery index of the target block, Calculate the initial suction index I of the target block CO2 :

[0019]

[0020] In step 1, the gas injection index multiple is calculated based on the test data of the gas injection block.

[0021] In step 1, for the gas injection block 1, the initial gas absorption index of block 1 is obtained by the initial gas absorption indicator curve test. The initial water-free rice production index of Block 1 was obtained by combining the oil and liquid production index curve with the test oil and production data. If there are many gas injection blocks, select test data of blocks with similar reservoir types and calculate the average value:

[0022]

[0023] In step 1, the initial water-free rice production index of the target block is calculated by combining the test oil and production data of the target block with the specific oil and liquid production index curve.

[0024] In step 2, for the implemented gas injection block 1, the starting pressure gradient g1 of the implemented gas injection block is calculated based on the initial starting pressure G1 of the implemented gas injection block 1 and the average injection-production well spacing L1 of the implemented gas injection block 1. The initial starting pressure G1 of the implemented gas injection block 1 is obtained according to the initial gas suction indicator curve test:

[0025]

[0026] In step 3, based on the relative starting pressure gradient and fluidity The relationship curve of the target block is used to determine the relative starting pressure gradient The relative starting pressure gradient is relative to the gas injection block 1 where the gas injection has already been implemented.

[0027] In step 3, the indoor starting pressure gradient γ and mobility of the target block and the oil field where the gas injection block is located are used to calculate the starting pressure gradient γ and mobility of the target block and the oil field where the gas injection block is located. The relative starting pressure gradient is obtained by converting the relationship curve and fluidity relationship curve.

[0028] In step 3, according to the flow rate of the gas injection block 1 Indoor starting pressure gradient γ and fluidity The indoor starting pressure gradient γ1 of the gas injection block is obtained from the relationship curve of the indoor starting pressure gradient γ and the mobility. The vertical coordinate of the relationship curve is the indoor starting pressure gradient γ. The data is uniformly divided by the indoor starting pressure gradient γ1 of the gas injection block 1 to obtain the relative starting pressure gradient and fluidity relationship curve.

[0029] In step 4, by determining the maximum pump pressure P 泵 , Wellbore liquid column pressure P 柱 , formation pressure P i , Target block starting pressure G 目标 The gas injection pressure difference ΔP of the target block is calculated:

[0030] ΔP=P 泵 +P 柱 -P i -G 目标 (4).

[0031] In step 4, the maximum pump pressure P 泵 Depends on the injection pump's pressure rating.

[0032] In step 4, the wellbore fluid column pressure P is calculated by the reservoir depth H and the average density of the wellbore fluid ρ 柱 :

[0033] P 柱 =ρgH (5).

[0034] In step 4, the formation pressure P i Equal to the current average reservoir pressure.

[0035] In step 4, the relative starting pressure gradient of the target block relative to the gas injection block 1 is used. The starting pressure gradient g1 of the implemented gas injection block 1 and the average injection-production well spacing L of the target block 目标 Calculate the target block starting pressure G 目标 :

[0036]

[0037] In step 5, the sand body thickness of the target block should be taken as the average sand body thickness h of the reservoir.

[0038] In step 6, the calculation formula for the initial injection capacity q of CO2 flooding is expressed as:

[0039] q=I CO2 ·h·ΔP (7)

[0040] Where, I CO2 is the initial rice aspiration index of the target block;

[0041] h is the thickness of the sand body in the target block;

[0042] ΔP is the injection pressure difference in the target block.

[0043] The method for calculating the initial injectivity of CO2 flooding in low-permeability reservoirs in this invention can provide a method for determining key technical policies for the preparation of CO2 flooding engineering plans for low-permeability reservoirs, thereby providing guidance for the preparation of CO2 flooding engineering plans. Compared with existing technologies, this invention has the following advantages:

[0044] (1) For the first time, a reservoir engineering calculation method for the initial injection capacity of CO2 flooding in low-permeability reservoirs is proposed. With the proposal of the national dual carbon goals, CO2 flooding and storage technology is becoming increasingly important. However, CO2 flooding and storage in major domestic oil fields are still in the pilot or expanded trial stage. There are few reports on the calculation method of the initial injection capacity of low-permeability reservoirs. In particular, this patent proposes a reservoir engineering method for the first time.

[0045] (2) The method proposed in this patent for calculating the initial injection capacity of CO2 flooding in low-permeability reservoirs has high accuracy. The method proposed in this patent is similar to a semi-empirical analogy method and can fully consider the characteristics of the reservoir itself. These characteristics include reservoir properties that can be described by other calculation formulas (thickness, permeability, porosity, etc.), as well as many reservoir properties that are difficult to describe (heterogeneity, reservoir effectiveness, connectivity, etc.).

[0046] (3) The method proposed in this patent for calculating the initial injection capacity of CO2 flooding in low-permeability reservoirs is highly operational. Compared with other complex numerical calculation methods and numerical simulation methods, this method belongs to the reservoir engineering calculation method and has strong field operability. BRIEF DESCRIPTION OF THE DRAWINGS

[0047] Figure 1 This is a flow chart of a specific embodiment of the method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to the present invention;

[0048] Figure 2This is a calculation diagram of the air inhalation index multiple of block A in a specific embodiment of the present invention;

[0049] Figure 3 A graph showing the relationship between the starting pressure gradient and the fluidity in a specific embodiment of the present invention;

[0050] Figure 4 FIG. 1 is a graph showing the relationship between the relative starting pressure gradient and the fluidity relative to block A in a specific embodiment of the present invention. DETAILED DESCRIPTION

[0051] It should be noted that the following detailed descriptions are exemplary and intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those skilled in the art to which the present invention belongs.

[0052] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is intended to include the plural form. In addition, it should be understood that when the terms "comprise" and / or "include" are used in this specification, they indicate the presence of features, steps, operations and / or combinations thereof.

[0053] like Figure 1 As shown, Figure 1 The flowchart of the method for calculating the initial injection capacity of CO2 flooding in low permeability reservoirs of the present invention includes the following steps:

[0054] Step 101, calculating the initial rice aspiration index of the target block;

[0055] According to the gas absorption index multiple β and the initial water-free rice oil production index of the target block Calculate the initial suction index I of the target block CO2 .

[0056]

[0057] The multiple of the initial air intake index can be calculated by the test data of the gas injection block. For the gas injection block 1, the initial air intake index of block 1 can be obtained by the initial air intake indicator curve test. The initial water-free rice production index of Block 1 was obtained by combining the oil and liquid production index curve with the test oil and production data. If there are many blocks where gas injection has been implemented, the test data of blocks with similar reservoir types can be selected for calculation and averaged.

[0058]

[0059] The initial water-free rice production index of the target block used to calculate the initial rice absorption index can be obtained by combining the target block test oil and test production data with the specific oil and liquid production index curve.

[0060] Step 102, calculating the starting pressure gradient of the implemented block;

[0061] For the implemented gas injection block 1, the starting pressure gradient g1 of the implemented gas injection block is calculated based on the initial starting pressure G1 of the implemented gas injection block 1 and the average injection-production well spacing L1 of the implemented gas injection block 1. The initial starting pressure G1 of the implemented gas injection block 1 can be obtained based on the initial gas suction indication curve test.

[0062]

[0063] Step 103, calculating the relative starting pressure gradient of the target block;

[0064] According to the relative starting pressure gradient and fluidity The relationship curve of the target block is used to determine the relative starting pressure gradient The relative starting pressure gradient here is relative to the gas injection block 1 where gas injection has been implemented.

[0065] In step 3, the relative starting pressure gradient for determining the relative starting pressure gradient of the target block is and fluidity The relationship curve between the indoor starting pressure gradient γ and the mobility of the target block and the oil field where the gas injection block is located (hereinafter referred to as the indoor starting pressure gradient) can be used to calculate the relationship between the indoor starting pressure gradient γ and the mobility of the target block and the oil field where the gas injection block is located. According to the flow rate of gas injection block 1, Indoor starting pressure gradient γ and fluidity The indoor starting pressure gradient γ1 of the gas injection block is obtained from the relationship curve of the indoor starting pressure gradient γ and the mobility. The vertical coordinate of the relationship curve (indoor starting pressure gradient γ) is divided by the indoor starting pressure gradient γ1 of the gas injection block 1 to obtain the relative starting pressure gradient and fluidity relationship curve.

[0066] Step 104, calculating the gas injection pressure difference of the target block;

[0067] The injection pressure difference ΔP of the target block can be determined by determining the maximum pump pressure P 泵 , Wellbore liquid column pressure P 柱 , formation pressure P i , Target block starting pressure G 目标 Perform calculations.

[0068] ΔP=P 泵 +P 柱 -P i -G 目标 (4)

[0069] The maximum pump pressure used to calculate the injection pressure differential depends on the injection pump's rated pressure.

[0070] Wellbore liquid column pressure P used to calculate gas injection pressure difference 柱 It can be calculated by the reservoir depth H and the average density ρ of the wellbore fluid.

[0071] P 柱 =ρgH (5)

[0072] The formation pressure used to calculate the injection pressure difference should be equal to the current average reservoir pressure.

[0073] The target block starting pressure for calculating the injection pressure difference can be obtained by calculating the relative starting pressure gradient of the target block relative to the implemented gas injection block 1. The starting pressure gradient g1 of the implemented gas injection block 1 and the average injection-production well spacing L of the target block 目标 Obtained by calculation.

[0074]

[0075] Step 105: Determine the sand body thickness of the target block; the sand body thickness of the target block should be the average sand body thickness h of the reservoir.

[0076] Step 106: Calculate the initial CO2 flooding injection capacity of the target block according to the CO2 injection capacity calculation formula.

[0077] The calculation formula of CO2 flooding initial injection capacity q is expressed as:

[0078] q=I CO2 ·h·ΔP

[0079] The following are several specific embodiments of the present invention.

[0080] Example 1

[0081] In a specific embodiment 1 of the present invention, the method for calculating the initial injectivity of CO2 flooding in a low permeability reservoir includes:

[0082] In step 1, the initial gas absorption index of the target block is calculated according to the gas absorption index multiple and the initial water-free oil production index of the target block.

[0083] Shengli Oilfield has conducted a CO2 flooding pilot test in Block A. Block A has a permeability of 4 mD, making it a low-permeability reservoir. During the pilot test, the gas absorption curve was repeatedly tested. The initial gas absorption index (GAI) was determined based on the initial gas absorption curve. The initial water-free GAI was determined based on the test and production data and the specific oil and liquid production index curve. A relationship diagram was created between the initial GAI and the initial water-free GAI for Block A ( Figure 2 ), make a regression curve between the two. From formula (2), we can know that the slope of the curve is the suction index multiple of block A. According to calculation, the suction index multiple of block A is 2.4-3.8, and the value here is 3.1.

[0084] The target block is Block B, whose reservoir permeability is 35 mD. Based on the test oil and production data for this block, its initial permeability index is determined to be 0.019 t / d.MPa.m. When Block B was first put into production, its water content was 47%. Based on the relative permeability curve and fluid parameters for this block, a specific oil and liquid production index curve was plotted, further converting the initial water-free production index of Block B to 0.06 t / d.MPa.m. According to formula (1), the initial permeability index of the injection wells in Block B can be calculated to be 0.186 t / d.MPa.m.

[0085] In step 2, for the gas injection block implemented, the starting pressure gradient of the gas injection block implemented is calculated according to the initial starting pressure of the gas injection block implemented and the average injection-production well spacing of the gas injection block implemented.

[0086] The initial start-up pressure can be determined based on the initial gas suction indication curve of Block A. The average start-up pressure of the injection wells in Block A is 10.5 MPa. The average injection-production well spacing in Block A is 350 m. The start-up pressure gradient of Block A is calculated to be 6 MPa / 100 m according to formula (3).

[0087] In step 3, the relative starting pressure gradient of the target block is determined according to the relationship curve between the relative starting pressure gradient and the mobility.

[0088] Cores with different permeabilities from the oil field where Block A is located were selected and the relationship curve between the starting pressure gradient and mobility was tested through indoor experiments ( Figure 3 The viscosity of the underground crude oil in block A is 1.6mPa.s, so the fluidity of block A is 2.5. The relationship curve between the starting pressure gradient and fluidity shows that the starting pressure gradient of block A in the indoor experimental test is 0.004MPa / cm. The vertical coordinate of the relationship curve between the starting pressure gradient and fluidity is divided by the starting pressure gradient of block A in the indoor experimental test (0.004), and the relationship curve between the relative starting pressure gradient and fluidity relative to block A can be obtained ( Figure 4The viscosity of the underground crude oil in the target block B is 4.5 mPa.s. The mobility of block B is calculated to be 7.8. The relationship curve between the relative starting pressure gradient and mobility relative to block A shows that the relative starting pressure gradient of block B relative to block A is 0.5.

[0089] In step 4, the injection pressure difference of the target block can be calculated by determining the maximum pump pressure, the wellbore fluid column pressure, the formation pressure, and the starting pressure of the target block.

[0090] The rated pressure (maximum pump pressure) of a general mine injection pump is 30 MPa. The depth of the B block reservoir is 3350m. Through testing, it was found that the average density of the injected liquid CO2 in the wellbore is 0.87g / cm 3 , the wellbore liquid column pressure is calculated to be 28.5 MPa using formula (5). Through pressure testing, the formation pressure of Block B is determined to be 29.5 MPa. The starting pressure of Block B is calculated to be 5.2 MPa using formula (6). According to formula (4), the injection pressure difference of target Block B is calculated to be 23.8 MPa.

[0091] In step 5, the average sand body thickness of the Block B reservoir is determined to be 19.7 m.

[0092] In step 6, the CO2 injection capacity of block B is calculated to be 87.2 t / d according to formula (7).

[0093] Example 2

[0094] In a specific embodiment 2 of the present invention, the method for calculating the initial injectivity of CO2 flooding in a low permeability reservoir includes:

[0095] In step 1, the initial gas absorption index of the target block is calculated according to the gas absorption index multiple and the initial water-free oil production index of the target block.

[0096] The calculated suction index multiple of block A is 2.4-3.8, and the value here is 2.4.

[0097] The target block is Block C, whose reservoir permeability is 1 mD and the injection-production well spacing is 370 m. Based on the oil and production test data from this block, its initial per-meter oil recovery index is determined to be 0.067 t / d.MPa.m. Block C contains virtually no water during its initial production. Using formula (1), the initial per-meter gas absorption index of the injection wells in Block C can be calculated to be 0.16 t / d.MPa.m.

[0098] In step 2, for the gas injection block implemented, the starting pressure gradient of the gas injection block implemented is calculated according to the initial starting pressure of the gas injection block implemented and the average injection-production well spacing of the gas injection block implemented.

[0099] The starting pressure gradient of block A is calculated to be 6 MPa / 100m.

[0100] In step 3, the relative starting pressure gradient of the target block is determined according to the relationship curve between the relative starting pressure gradient and the mobility.

[0101] Relationship curve between relative starting pressure gradient and fluidity relative to block A ( Figure 4 The viscosity of the underground crude oil in the target block C is 1.4 mPa.s. The calculated mobility of block C is 0.7. The relationship curve between the relative starting pressure gradient and mobility relative to block A shows that the relative starting pressure gradient of block C relative to block A is 1.72.

[0102] In step 4, the injection pressure difference of the target block can be calculated by determining the maximum pump pressure, the wellbore fluid column pressure, the formation pressure, and the starting pressure of the target block.

[0103] The rated pressure (maximum pump pressure) of a general mine injection pump is 30 MPa. The depth of the C block reservoir is 3250 m. Through testing, it was found that the average density of injected liquid CO2 in the wellbore is 0.87 g / cm 3 , the wellbore fluid column pressure is calculated to be 27.8 MPa using formula (5). Through pressure testing, the formation pressure in Block C is determined to be 31 MPa. The starting pressure of Block C is calculated to be 19 MPa using formula (6). Based on formula (4), the injection pressure difference in target Block C is calculated to be 7.8 MPa.

[0104] In step 5, the average sand body thickness of the C block reservoir is determined to be 20.3 m.

[0105] In step 6, the CO2 injection capacity of block C is calculated to be 25.3 t / d according to formula (7).

[0106] Example 3

[0107] In a specific embodiment 3 of the present invention, the method for calculating the initial injectivity of CO2 flooding in a low permeability reservoir includes:

[0108] In step 1, the initial gas absorption index of the target block is calculated according to the gas absorption index multiple and the initial water-free oil production index of the target block.

[0109] The calculated suction index multiple of block A is 2.4-3.8, and the value here is 3.8.

[0110] The target block is Block D, whose reservoir permeability is 3 mD and the injection-production well spacing is 470 m. Based on the oil and production test data for this block, its initial permeability index is determined to be 0.047 t / d.MPa.m. When Block D was initially put into production, its water content was 20%. Based on the relative permeability curve and fluid parameters for this block, a specific oil and liquid production index curve was plotted, further converting the initial water-free oil production index of Block D to 0.059 t / d.MPa.m. According to formula (1), the initial permeability index of the injection wells in Block D can be calculated to be 0.23 t / d.MPa.m.

[0111] In step 2, for the gas injection block implemented, the starting pressure gradient of the gas injection block implemented is calculated according to the initial starting pressure of the gas injection block implemented and the average injection-production well spacing of the gas injection block implemented.

[0112] The starting pressure gradient of block A is calculated to be 6 MPa / 100m.

[0113] In step 3, the relative starting pressure gradient of the target block is determined according to the relationship curve between the relative starting pressure gradient and the mobility.

[0114] Relationship curve between relative starting pressure gradient and fluidity relative to block A ( Figure 4 The viscosity of the underground crude oil in the target block D is 1.5 mPa.s. The mobility of block D is calculated to be 2. The relationship curve between the relative starting pressure gradient and mobility relative to block A shows that the relative starting pressure gradient of block D relative to block A is 1.4.

[0115] In step 4, the injection pressure difference of the target block can be calculated by determining the maximum pump pressure, the wellbore fluid column pressure, the formation pressure, and the starting pressure of the target block.

[0116] The rated pressure (maximum pump pressure) of a general mine injection pump is 30 MPa. The depth of the D block reservoir is 2950 m. Through testing, it was found that the average density of the injected liquid CO2 in the wellbore is 0.87 g / cm 3 , the wellbore fluid column pressure is calculated to be 25.1 MPa using formula (5). Through pressure testing, the formation pressure in block D is determined to be 20 MPa. The starting pressure of block D is calculated to be 19.8 MPa using formula (6). Based on formula (4), the injection pressure difference in target block D is calculated to be 15.3 MPa.

[0117] In step 5, the average sand body thickness of the D block reservoir is determined to be 16.4 m.

[0118] In step 6, the CO2 injection capacity of block D is calculated to be 57.7 t / d according to formula (7).

[0119] 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 aforementioned embodiments, those skilled in the art may modify the technical solutions described in the aforementioned embodiments or substitute equivalents for some of the technical features therein. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention shall be included within the scope of protection of the present invention.

[0120] Except for the technical features described in the specification, all other technical features are known technologies to those skilled in the art.

Claims

1. A method for calculating the initial injection capacity of CO2 flooding in low permeability reservoirs, characterized by: The calculation method of the initial injection capacity of CO2 flooding in low permeability reservoirs includes: Step 1, calculate the initial rice aspiration index of the target block; Step 2: Calculate the starting pressure gradient of the gas injection block; Step 3, calculating the relative starting pressure gradient of the target block; Step 4, calculating the gas injection pressure difference of the target block; Step 5, determining the sand body thickness of the target block; Step 6: Calculate the initial CO2 injection capacity of the target block according to the CO2 injection capacity calculation formula; The calculation formula of CO2 flooding initial injection capacity q is expressed as: q=I CO2 ·h·ΔP (7) Where, I CO2 is the initial rice aspiration index of the target block; h is the thickness of the sand body in the target block; ΔP is the gas injection pressure difference in the target block; In step 3, based on the relative starting pressure gradient and fluidity The relationship curve of the target block is used to determine the relative starting pressure gradient The relative starting pressure gradient is relative to the gas injection block; The indoor starting pressure gradient γ and mobility of the target block and the oil field where the gas injection block is located are analyzed. The relative starting pressure gradient is obtained by converting the relationship curve and fluidity The relationship curve of According to the flow rate of the implemented gas injection block Indoor starting pressure gradient γ and fluidity The indoor starting pressure gradient γ1 of the gas injection block is obtained from the relationship curve of the indoor starting pressure gradient γ and the mobility. The vertical coordinate of the relationship curve is the indoor starting pressure gradient γ data divided by the indoor starting pressure gradient γ1 of the gas injection block, and the relative starting pressure gradient can be obtained. and fluidity relationship curve.

2. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 1, characterized in that: In step 1, according to the gas absorption index multiple β and the initial water-free rice oil recovery index of the target block, Calculate the initial suction index I of the target block CO2 :

3. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 2, characterized in that: In step 1, the gas injection index multiple is calculated based on the test data of the gas injection block.

4. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 3, characterized in that: In step 1, the initial gas absorption index of the gas injection block is obtained by testing the initial gas absorption index curve. The initial water-free oil production index of the gas injection block was obtained by combining the oil and liquid production index curve with the test oil and production data. If there are many gas injection blocks, select test data of blocks with similar reservoir types and calculate the average value:

5. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 2, characterized in that: In step 1, the initial water-free rice production index of the target block is calculated by combining the test oil and production data of the target block with the specific oil and liquid production index curve.

6. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 1, characterized in that: In step 2, for the gas injection block, the starting pressure gradient g1 of the gas injection block is calculated based on the initial starting pressure G1 of the gas injection block and the average injection-production well spacing L1 of the gas injection block. The initial starting pressure G1 of the gas injection block is obtained according to the initial gas suction indicator curve test:

7. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 1, characterized in that: In step 4, by determining the maximum pump pressure P 泵 , Wellbore liquid column pressure P 柱 , formation pressure P i , Target block starting pressure G 目标 The gas injection pressure difference ΔP of the target block is calculated: ΔP=P 泵 +P 柱 -P i -G 目标 (4)。 8. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 7, characterized in that: In step 4, the maximum pump pressure P 泵 Depends on the injection pump's pressure rating.

9. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 7, characterized in that: In step 4, the wellbore fluid column pressure P is calculated by the reservoir depth H and the average density of the wellbore fluid ρ 柱 : P 柱 =ρgH (5)。 10. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 7, characterized in that: In step 4, the formation pressure P i Equal to the current average reservoir pressure.

11. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 7, characterized in that: In step 4, the relative starting pressure gradient of the target block relative to the gas injection block is used to The starting pressure gradient g1 of the implemented gas injection block and the average injection-production well spacing L of the target block 目标 Calculate the target block starting pressure G 目标 :

12. The method for calculating the initial injectivity of CO2 flooding in low permeability reservoirs according to claim 1, characterized in that: In step 5, the sand body thickness of the target block should be taken as the average sand body thickness h of the reservoir.

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