A method and system for carbon dioxide flooding and storage well spacing decision

Abstract

The application provides a carbon dioxide oil displacement sealing well spacing decision method and system, which comprises the following steps: firstly, carrying out crude oil-CO2 phase state experiment of a target reservoir to determine the viscosity variation characteristics of crude oil before and after CO2 injection; calculating the starting pressure gradient according to the viscosity of crude oil before gas injection and the minimum viscosity of crude oil after gas injection reflected by the experiment; then calculating the minimum driving pressure gradient under different injection-production well spacings to determine the injection-production well spacing before and after gas injection; calculating the economic limit well spacing and the economic best well spacing of the target reservoir by using the curve intersection method; determining the relationship curves between the well spacing and the CO2 displacement miscible degree and the CO2 displacement component sweep efficiency respectively; and selecting the target well spacing by comprehensively considering the distribution characteristics of the injection-production well spacing before and after gas injection, the economic limit well spacing and the economic best well spacing. The scheme can overcome the problems of the prior art, such as incomplete consideration of factors and insufficient accuracy of well spacing range selection, and forms an efficient and reliable well spacing calculation method by comprehensively considering the CO2 oil displacement mechanism, the reservoir characteristics and the economic benefits.

Description

Technical Field

[0001] This invention relates to the field of oilfield development and optimization technology, and in particular to a method and system for determining well spacing in carbon dioxide flooding and storage. Background Technology

[0002] CO2 flooding technology can achieve a win-win situation of increasing oil production and reducing carbon emissions, and therefore has attracted widespread attention. From a technical perspective, compared with other enhanced oil recovery technologies, CO2 flooding has many advantages. For example, CO2 has strong injection capacity, can extract light components, reduce crude oil viscosity, expand crude oil volume, and is miscible with crude oil, improving its flowability. Especially in the development of general low-permeability and ultra-low-permeability reservoirs, CO2 flooding can effectively solve problems such as difficulties in water injection development and ineffective energy replenishment in these reservoirs.

[0003] However, in actual operation, construction parameters have a significant impact on the effectiveness of oil displacement projects. In CO2 flooding operations, well spacing affects not only the oil displacement effect but also economic benefits. Currently, CO2 flooding technology lacks a mature method for calculating well spacing; the following existing methods for determining well spacing have some problems:

[0004] ① Borrowing from the concept of waterflooding technology, the maximum technical well spacing is calculated using the oil phase initiation pressure gradient. However, this method does not consider the changes in fluid properties after CO2 injection, and the calculation results are less reliable compared to CO2 flooding technology.

[0005] ② Component numerical simulation method: This method uses a component numerical simulation model to calculate recovery rate, oil exchange rate, and carbon retention rate under different well spacings, and selects a suitable well spacing. This method has two problems: first, it has high requirements for the selection of the well spacing range; an unreasonable well spacing range may prevent convergence to the optimal solution; second, oil exchange rate and carbon retention rate are two contradictory indicators, and it is impossible to select the optimal well spacing when both indicators are used simultaneously.

[0006] ③ Economic Limit Well Spacing: Borrowing from the waterflooding approach, this method calculates the economic well spacing based on reservoir reserves. The problem with this method is that it can only determine economically reasonable well spacing and cannot take into account the carbon dioxide displacement mechanism and characteristics.

[0007] To address the above issues, it is necessary to comprehensively consider the reservoir characteristics and economic benefits of CO2 flooding technology and develop a well spacing calculation method suitable for CO2 flooding.

[0008] The information disclosed in the background section of this invention is intended only to enhance the understanding of the general background of this invention, and should not be construed as an admission or in any way implying that such information constitutes prior art known to those skilled in the art. Summary of the Invention

[0009] To address the aforementioned problems, this invention provides a method for determining well spacing in carbon dioxide flooding and storage. This method overcomes the shortcomings of existing technologies, such as incomplete consideration of factors and insufficient accuracy in well spacing selection. It integrates the CO2 flooding mechanism, reservoir characteristics, and economic benefits to form an efficient and reliable well spacing calculation method. The method first conducts crude oil-CO2 phase state experiments on the target reservoir to clarify the viscosity changes of crude oil before and after CO2 injection. Based on the crude oil viscosity before injection and the minimum crude oil viscosity after injection as reflected in the experiments, the starting pressure gradient is calculated. Then, the minimum driving pressure gradient under different injection-production well spacings is calculated to determine the injection-production well spacing before and after injection. The economic limit well spacing and the economically optimal well spacing of the target reservoir are calculated using the curve intersection method. The relationship curves between well spacing and the degree of miscibility of CO2 flooding and the sweep efficiency of CO2 flooding components are determined respectively. The target well spacing is selected by comprehensively considering the distribution characteristics of the injection-production well spacing before and after injection, the economic limit well spacing, and the economically optimal well spacing. Preferably, in one embodiment, the method includes:

[0010] Step S100: Conduct crude oil-CO2 phase state experiments in the target reservoir to clarify the viscosity change characteristics of crude oil before and after CO2 injection;

[0011] Step S200: Calculate the starting pressure gradient based on the crude oil viscosity before gas injection and the minimum crude oil viscosity after gas injection as reflected in the experiment;

[0012] Step S300: Calculate the minimum driving pressure gradient under different injection-production well spacing, and obtain the injection-production well spacing before and after gas injection by combining the starting pressure gradient;

[0013] Step S400: Calculate the economic limit well spacing and the economic optimal well spacing of the target reservoir using the curve intersection method;

[0014] Step S500: Determine the relationship curves between well spacing and CO2 flooding miscibility and CO2 flooding component sweep efficiency, and select the target well spacing by comprehensively considering the distribution characteristics of injection-production well spacing before and after gas injection, economic limit well spacing, and economic optimal well spacing.

[0015] In an optional embodiment, in step S200, the starting pressure gradient is calculated using the following formula:

[0016]

[0017]

[0018] Among them, G DI1 To initiate the pressure gradient before gas injection, G DI2 The starting pressure gradient after gas injection; K is the reservoir permeability; μ oi The viscosity of the crude oil before gas injection is μ. oco2 This represents the minimum crude oil viscosity after gas injection.

[0019] Furthermore, in one embodiment, in step S300, the minimum driving pressure gradient under different injection-production well distances is calculated by using the formation pressure before gas injection, the bottom pressure of the injection well, and the bottom flowing pressure of the production well, combined with the well distance.

[0020] The minimum driving pressure gradient that is consistent with the starting pressure gradient before and after gas injection is selected respectively, and the well distance corresponding to it is taken as the injection-production well distance before and after gas injection.

[0021] Preferably, in one embodiment, in step S300, the minimum driving pressure gradient under different injection-production well spacings is calculated using the following formula:

[0022]

[0023] In one embodiment, in step S400, a first economic calculation model and a second economic calculation model are established based on the set oil price and carbon dioxide price, respectively.

[0024] Plot the curves of the changes in values ​​of the first economic calculation model and the second economic calculation model with well network density, respectively. Select the well distance corresponding to the well network density at the intersection of the two curves as the economic limit well distance under the oil price and carbon dioxide price.

[0025] Optionally, in one embodiment, the following first economic operation model is adopted:

[0026] y1=[NE D e -a / s / t]G[(1+i) t -1] / i

[0027] The following second economic operation model is adopted:

[0028] y2 = ASM(1+i) t +ASP[(1+i) t -1] / i

[0029] In the formula, A represents the oil-bearing area; y1 and y2 are the first and second indicators for determining the economic limit well density through cross-plotting; N represents the crude oil geological reserves; E D The following values ​​represent the oil displacement efficiency; a represents the well network index; i represents the annual loan interest rate; P represents the annual maintenance and management cost and CO2 total cost per well; G represents the sales price per ton of oil; M represents the investment in drilling and surface construction per well; t represents the development evaluation period; and S represents the well network density.

[0030] Preferably, in one embodiment, in step S400, a third economic calculation model and a fourth economic calculation model are established based on the set oil price and carbon dioxide price, respectively.

[0031] Plot the curves of the numerical values ​​of the third and fourth economic operation models as a function of well density, and select the well spacing corresponding to the well density at the intersection of the two curves as the economically optimal well spacing under the oil price and carbon dioxide price.

[0032] Furthermore, in one embodiment, the following third economic operation model is adopted:

[0033] y3=[aNG E D / t]{[(1+i) t -1] / i}e -a / s

[0034] The following fourth economic operation model is adopted:

[0035] y4={M(1+i) t +P[(1+i) t -1] / i}AS 2

[0036] In the formula, A represents the oil-bearing area; y3 and y4 are the third and fourth indicators for determining the economically optimal well density through cross-plotting; N represents the crude oil geological reserves; E D The following values ​​represent the oil displacement efficiency; a represents the well network index; i represents the annual loan interest rate; P represents the annual maintenance and management cost and CO2 total cost per well; G represents the sales price per ton of oil; M represents the investment in drilling and surface construction per well; t represents the development evaluation period; and S represents the well network density.

[0037] Optionally, in one embodiment, in step S500, using component numerical simulation technology, for the target work area, the relationship curves between well spacing and CO2 flooding miscibility, and between well spacing and CO2 flooding component sweep efficiency are simulated and calculated respectively. The overlapping intervals of injection and production well spacing before and after gas injection and between the economic limit well spacing and the economic optimal well spacing are configured. Then, the well spacing with the largest product of CO2 flooding miscibility and component sweep efficiency is selected from the overlapping interval as the target well spacing.

[0038] Based on other aspects of the methods described in any one or more of the foregoing embodiments, the present invention also provides a storage medium storing program code that can implement the methods described in any one or more of the foregoing embodiments.

[0039] Based on the application aspects of the methods described in any one or more of the above embodiments, the present invention also provides a carbon dioxide flooding and storage well spacing decision system, which executes the methods described in any one or more of the above embodiments.

[0040] Compared with the closest prior art, the present invention also has the following beneficial effects:

[0041] This invention provides a method and system for determining well spacing in carbon dioxide flooding and storage. The method first conducts crude oil-CO2 phase experiments on the target reservoir to clarify the viscosity changes of crude oil before and after CO2 injection. Based on the crude oil viscosity before injection and the minimum crude oil viscosity after injection as reflected in the experiments, the starting pressure gradient is calculated. Then, the minimum driving pressure gradient under different injection-production well spacings is calculated to determine the injection-production well spacing before and after injection. The economic limit well spacing and the economically optimal well spacing of the target reservoir are calculated using the curve intersection method. The relationship curves between well spacing and the degree of miscibility and the component sweep efficiency of CO2 flooding are determined respectively. The target well spacing is selected by comprehensively considering the distribution characteristics of the injection-production well spacing before and after injection, the economic limit well spacing, and the economically optimal well spacing. This method comprehensively considers the relationship between the change in the starting pressure gradient of the oil phase after CO2 dissolution, the degree of miscibility, the component sweep efficiency, and the well spacing. Using the curve intersection method and component numerical simulation technology, based on the changes in the degree of miscibility and the component sweep efficiency, combined with the technical and economic well spacing ranges, the final reasonable well spacing is determined. This method is not only reliably applicable to the CO2 flooding mechanism but also ensures the rationality of economic benefits, making it more practical.

[0042] 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 description, claims and drawings. Attached Figure Description

[0043] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0044] Figure 1 This is a flowchart illustrating the carbon dioxide flooding and storage well spacing decision method provided in an embodiment of the present invention;

[0045] Figure 2 This is a schematic diagram of the carbon dioxide flooding and storage well spacing decision system provided in another embodiment of the present invention. Detailed Implementation

[0046] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples. Those skilled in the art will then fully understand how the present invention uses technical means to solve technical problems and achieve technical effects, and will be able to implement the present invention specifically based on the above-described implementation process. It should be noted that, as long as there is no conflict, the various embodiments and features of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0047] Although the flowchart describes the operations as sequential processes, many of these operations can be performed in parallel, concurrently, or simultaneously. The order of the operations can be rearranged. A process can terminate when its operation is complete, but it may also have additional steps not included in the diagram. A process can correspond to a method, function, procedure, subroutine, subroutine, etc.

[0048] Computer equipment includes user equipment and network equipment. User equipment or clients include, but are not limited to, computers, smartphones, and PDAs (Personal Digital Assistants); network equipment includes, but is not limited to, a single network server, a server group consisting of multiple network servers, or a cloud based on cloud computing consisting of a large number of computers or network servers. Computer equipment can operate independently to implement this invention, or it can connect to a network and implement this invention through interaction with other computer devices within the network. The network in which the computer equipment resides includes, but is not limited to, the Internet, wide area networks (WANs), metropolitan area networks (MANs), local area networks (LANs), and VPN networks.

[0049] The terms “first,” “second,” etc., may be used herein to describe various units, but these units should not be limited by these terms; they are used merely to distinguish one unit from another. The term “and / or” as used herein includes any and all combinations of one or more of the associated listed items. When a unit is referred to as “connected” or “coupled” to another unit, it may be directly connected or coupled to said other unit, or there may be intermediate units present.

[0050] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms “a” and “an” as used herein are also intended to include the plural. It should also be understood that the terms “comprising” and / or “including” as used herein specify the presence of the stated features, integers, steps, operations, units, and / or components, without excluding the presence or addition of one or more other features, integers, steps, operations, units, components, and / or combinations thereof.

[0051] In the oilfield development sector, CO2 flooding technology has attracted widespread attention because it can achieve a win-win situation of increasing oil production and reducing carbon emissions. Many petrochemical projects have already implemented CO2 flooding projects with a capacity of millions of tons. Overseas, the annual output of CO2 flooding has consistently remained above 13 million tons per year, and the number of implemented projects has consistently remained above 100.

[0052] From a technical perspective, CO2 flooding enhanced oil recovery technology has many advantages compared to other technologies. For example, CO2 has strong injection capacity, can extract light components, reduce crude oil viscosity, expand crude oil volume, and is miscible with crude oil, thus improving its flowability. Especially in the development of general low-permeability and ultra-low-permeability reservoirs, CO2 flooding enhanced oil recovery technology can effectively solve problems such as difficulties in water injection development and ineffective energy replenishment in these reservoirs.

[0053] In actual operation, construction parameters have a significant impact on the effectiveness of oil displacement projects. In CO2 flooding operations, well spacing affects not only the oil displacement effect but also economic benefits. However, currently, there is a lack of mature well spacing calculation methods for CO2 flooding technology. The commonly used methods are as follows, and correspondingly, the following application problems exist:

[0054] ① Borrowing from the concept of waterflooding technology, the maximum technical well spacing is calculated using the oil phase initiation pressure gradient. However, this method does not consider the changes in fluid properties after CO2 injection, and the calculation results are less reliable compared to CO2 flooding technology.

[0055] ② Component numerical simulation method: This method uses a component numerical simulation model to calculate recovery rate, oil exchange rate, and carbon retention rate under different well spacings, and selects a suitable well spacing. This method has two problems: first, it has high requirements for the selection of the well spacing range; an unreasonable well spacing range may prevent convergence to the optimal solution; second, oil exchange rate and carbon retention rate are two contradictory indicators, and it is impossible to select the optimal well spacing when both indicators are used simultaneously.

[0056] ③ Economic Limit Well Spacing: Borrowing from the waterflooding approach, this method calculates the economic well spacing based on reservoir reserves. The problem with this method is that it can only determine economically reasonable well spacing and cannot take into account the carbon dioxide displacement mechanism and characteristics.

[0057] To address the above issues, it is necessary to develop a well spacing calculation method suitable for CO2 flooding, taking into account reservoir characteristics and economic benefits, based on the CO2 flooding mechanism. This invention addresses the problem of incomplete consideration of factors in current CO2 flooding well spacing calculation methods by providing a method for determining the well spacing of a target reservoir. This method comprehensively considers factors such as the change in oil phase initiation pressure gradient after CO2 dissolution, miscibility, and the relationship between component sweep efficiency and well spacing. Starting from the CO2 flooding mechanism and considering reservoir characteristics and economic benefits, the well spacing calculation results are more reasonable.

[0058] This invention, based on the CO2 flooding mechanism and considering reservoir characteristics and economic benefits, performs calculations from three aspects: first, it considers the change in the oil phase initiation pressure gradient after CO2 injection to determine a technical well spacing range; second, it uses the curve intersection method to determine the economic well spacing range; and third, it utilizes the changes in miscibility and component sweep efficiency, combined with the aforementioned technical and economic well spacing ranges, to determine the final reasonable well spacing. This invention considers the characteristics of crude oil viscosity changes during CO2 flooding and quickly calculates a more reasonable economic and technical well spacing using a matching formula. It is simple, fast, and the well spacing calculation results are more consistent with actual field conditions.

[0059] The following describes the detailed flow of the method according to an embodiment of the present invention with reference to the accompanying drawings, the steps of which can be executed in a computer system containing, for example, a set of computer-executable instructions. Although the logical order of the steps is shown in the flowchart, in some cases, the steps shown or described may be performed in a different order than that shown here.

[0060] Example 1

[0061] Figure 1 This diagram illustrates the flow chart of the carbon dioxide flooding and storage well spacing decision method provided in Embodiment 1 of the present invention. (Refer to...) Figure 1 As can be seen, the method includes the following steps.

[0062] Step S100: Conduct crude oil-CO2 phase state experiments in the target reservoir to clarify the viscosity change characteristics of crude oil before and after CO2 injection;

[0063] Step S200: Calculate the starting pressure gradient based on the crude oil viscosity before gas injection and the minimum crude oil viscosity after gas injection as reflected in the experiment;

[0064] Step S300: Calculate the minimum driving pressure gradient under different injection-production well spacing, and obtain the injection-production well spacing before and after gas injection by combining the starting pressure gradient;

[0065] Step S400: Calculate the economic limit well spacing and the economic optimal well spacing of the target reservoir using the curve intersection method;

[0066] Step S500: Determine the relationship curves between well spacing and CO2 flooding miscibility and CO2 flooding component sweep efficiency, and select the target well spacing by comprehensively considering the distribution characteristics of injection-production well spacing before and after gas injection, economic limit well spacing, and economic optimal well spacing.

[0067] This invention addresses the problem of incomplete consideration of factors in current CO2 flooding well spacing calculation methods by providing a method for calculating the well spacing of a target reservoir. Starting from the CO2 flooding mechanism, it considers reservoir characteristics and economic benefits, resulting in a more reasonable well spacing calculation. First, it considers the change in the oil phase initiation pressure gradient after CO2 injection, using a comparison between the minimum driving pressure gradient and the crude oil initiation pressure gradient to determine a range for technical well spacing. Second, it uses the curve intersection method to determine the range for economic well spacing. The oil displacement efficiency during calculation is determined using long core displacement tests, and CO2 recycling needs to be considered. Finally, by utilizing the changes in miscibility and component sweep efficiency, combined with the aforementioned technical and economic well spacing ranges, the final reasonable well spacing is determined. This invention is simple, fast, and the well spacing calculation results are more consistent with actual field conditions.

[0068] In a preferred embodiment, the crude oil viscosity change before and after gas injection in the target reservoir is first determined by the crude oil-CO2 phase experiment in step S100, and basic crude oil viscosity data is obtained. Typically, the CO2-crude oil phase experiment is carried out in accordance with the industry standard SY / T 7675.1-2023, which can determine the crude oil viscosity and its change characteristics before and after carbon dioxide injection.

[0069] Then, step S200 is executed to calculate the starting pressure gradient based on the crude oil viscosity before gas injection and the minimum crude oil viscosity after gas injection as reflected in the experiment.

[0070] In an optional embodiment, in step S200, the starting pressure gradient is calculated using the following formula:

[0071]

[0072]

[0073] Among them, G DI1 To initiate the pressure gradient before gas injection, G DI2 The starting pressure gradient after gas injection; K is the reservoir permeability; μ oi The viscosity of the crude oil before gas injection is μ. oco2 This represents the minimum crude oil viscosity after gas injection.

[0074] Furthermore, the minimum driving pressure gradient under different injection-production well distances is calculated through step S300, and the injection-production well distance before and after gas injection is obtained in combination with the starting pressure gradient.

[0075] Optionally, in one embodiment, in step S300, the minimum driving pressure gradient under different injection-production well distances is calculated by using the formation pressure before gas injection, the bottom pressure of the injection well, and the bottom flowing pressure of the production well, combined with the well distance.

[0076] Then, the minimum driving pressure gradient that is consistent with the starting pressure gradient before and after gas injection is selected, and the well distance corresponding to it is used as the injection-production well distance before and after gas injection.

[0077] Preferably, in one embodiment, the minimum driving pressure gradient under different injection-production well distances is calculated using the pre-injection formation pressure, injection well bottom-hole pressure, and production well bottom-hole flowing pressure, and the minimum driving pressure gradient G under different injection-production well distances is calculated using the following formula. DI :

[0078]

[0079] In the formula, G DI P represents the driving pressure gradient at point r, where R represents the well spacing; e p represents the formation pressure before gas injection. wf For the bottom hole pressure of the production well; p inf The bottom pressure of the injection well; r w R is the wellbore radius; R is the well spacing; r is a point in the formation.

[0080] Next, step S400 is executed, using the curve intersection method to calculate the economic limit well spacing and the economic optimal well spacing of the target reservoir.

[0081] In step S400, based on the set oil price and carbon dioxide price, a first economic calculation model and a second economic calculation model are established respectively.

[0082] Plot the curves of the numerical values ​​of the first and second economic calculation models as a function of well pattern density, and select the well pattern density S at the intersection of the two curves. lim As the economic limit well density, the well spacing corresponding to the economic limit well spacing under the given oil and carbon dioxide prices is the minimum economic well spacing. The limit well density refers to the well density at which profit is zero.

[0083] The economically optimal well density is the one at which the economic benefits are best.

[0084] In an optional embodiment, the following first economic operation model is adopted:

[0085] y1=[NE D e -a / s / t]G[(1+i) t -1] / i

[0086] The following second economic operation model is adopted:

[0087] y2 = ASM(1+i) t +ASP[(1+i) t -1] / i

[0088] In the formula, A represents the oil-bearing area, in km². 2 N represents crude oil geological reserves, in tons; E DThe oil displacement efficiency is represented by f (determined by long core displacement tests); a represents the well pattern index, in wells per km. 2 (CO2 flooding well network index); i represents the annual loan interest rate, f; P represents the annual maintenance and management cost per well + CO2 cost, yuan / well / year; G represents the sales price per ton of oil, yuan / ton; M represents the drilling and surface construction investment per well, yuan / well; T represents the development evaluation period, years; S represents the well network density, wells / km 2 t represents time, and the unit is years.

[0089] Furthermore, based on the set oil price and carbon dioxide price, a third economic operation model and a fourth economic operation model are established respectively;

[0090] Plot the curves of the numerical values ​​of the third and fourth economic operation models as a function of well density, and select the well spacing corresponding to the well density at the intersection of the two curves as the economically optimal well spacing under the oil price and carbon dioxide price.

[0091] In one optional embodiment, the following third economic operation model is adopted:

[0092] y3=[aNG E D / t]{[(1+i) t -1] / i}e -a / s

[0093] The following fourth economic operation model is adopted:

[0094] y4={M(1+i) t +P[(1+i) t -1] / i}AS 2

[0095] In the formula, A represents the oil-bearing area, in km². 2 N represents crude oil geological reserves, in tons; E D The oil displacement efficiency is represented by f (determined by long core displacement tests); a represents the well pattern index, in wells per km. 2 (CO2 flooding well network index); i represents the annual loan interest rate, f; P represents the annual maintenance and management cost per well + CO2 cost, yuan / well / year; G represents the sales price per ton of oil, yuan / ton; M represents the drilling and surface construction investment per well, yuan / well; T represents the development evaluation period, years; S represents the well network density, wells / km 2 .

[0096] Among them, the annual maintenance and management cost P for a single well includes the annual maintenance and management cost for a single well and the related costs of CO2; the related costs of CO2 include the injection cost (e.g., 40 yuan per ton) and the purchase cost (e.g., 300 yuan per ton, which refers to the cost to the wellhead).

[0097] Based on the above calculations, y1 and y2 are the first and second indicators for determining the economic limit well density through intersection. y1 represents the revenue after CO2 injection, calculated by the sweep efficiency based on the well density. Multiplying the sweep efficiency by the oil displacement efficiency gives the recovery rate, multiplying the recovery rate by the geological reserves gives the production, and multiplying by the crude oil sales price gives the revenue. y2 represents the expenditure, calculated by the number of wells based on the well density, and then calculating the total expenditure based on the investment in each well and the annual maintenance costs. When the total expenditure equals the total revenue, the limit well density can be calculated.

[0098] y3 and y4 are the third and fourth indicators used to determine the economically optimal well density through intersection analysis. As shown by y2, well density is a continuous function of profit (output), and it is differentiable within its domain. Therefore, profit is maximized when the first derivative is 0. Thus, differentiating y1 and y2 yields y3 and y4. The optimal well density (maximizing profit) is obtained when y3 and y4 are equal.

[0099] In practical applications, under normal conditions, the well spacing in water drive technology is greater than the economic well spacing, and the economic limit well spacing is less than the economic optimal well spacing.

[0100] Further, step S500 is executed to determine the relationship curves between well spacing and the degree of miscibility of CO2 flooding and the sweep efficiency of CO2 flooding components, and to select the target well spacing by comprehensively considering the distribution characteristics of injection-production well spacing before and after gas injection, economic limit well spacing and economic optimal well spacing.

[0101] Step S500: Determine the relationship curves between well spacing and CO2 flooding miscibility and CO2 flooding component sweep efficiency, and select the target well spacing by comprehensively considering the distribution characteristics of injection-production well spacing before and after gas injection, economic limit well spacing, and economic optimal well spacing.

[0102] In step S500, using component numerical simulation technology, the relationship curves between well spacing and CO2 flooding miscibility, and between well spacing and CO2 flooding component sweep efficiency are simulated and calculated for the target work area. The overlapping intervals of injection and production well spacing before and after gas injection, and between the economic limit well spacing and the economic optimal well spacing are configured. Then, the well spacing with the largest product of CO2 flooding miscibility and component sweep efficiency is selected from the overlapping intervals as the target well spacing.

[0103] Generally speaking, there is a correlation between miscibility and oil displacement efficiency. The product of oil displacement efficiency and sweep efficiency is positively correlated with oil recovery; therefore, the larger the product of oil displacement efficiency and sweep efficiency, the better the oil displacement effect. Within the intersection of [R1, R2] and [R3, R4], we identify the well spacing condition where the product of miscibility and sweep efficiency is largest; this well spacing is the one we recommend for implementation in the mining field.

[0104] In step S500, the process of simulating and calculating the relationship curve between the well spacing of the target work area and the degree of miscibility of CO2 flooding using component numerical simulation technology includes:

[0105] A numerical simulation model for CO2 injection was established based on the actual conditions of the reservoir, and numerical simulation calculations were performed.

[0106] Parameter field data at different times after CO2 injection were obtained based on numerical simulation results;

[0107] The miscibility coefficient C was calculated based on parameter field data at different times. p Near miscible volume coefficient C s ;

[0108] The degree of miscibility C under reservoir conditions is calculated based on the miscibility volume factor and the near-miscibility volume factor.

[0109] Calculate and determine the relationship curve between well spacing and CO2 flooding miscibility.

[0110] Among them, the miscibility volume factor C is calculated based on the gas phase saturation field data extracted from the numerical simulation results. p； The near-miscible volume coefficient Cs was calculated based on the interfacial tension field data extracted from the numerical simulation results.

[0111] The degree of miscibility C is calculated using the following formula:

[0112] C = Cp + Cs

[0113] The process of simulating and calculating the relationship curve between well spacing in the target work area and the sweep efficiency of CO2 flooding components using component numerical simulation technology includes:

[0114] A numerical simulation model for CO2 injection was established based on the actual conditions of the reservoir, and numerical simulation calculations were performed.

[0115] Parameter field data at different times after CO2 injection were obtained based on numerical simulation results;

[0116] The CO2 component sweep efficiency C was calculated based on parameter field data from different times. c .

[0117] Among them, the CO2 component sweep efficiency Cc is calculated based on the component field data extracted from the numerical simulation results.

[0118] The CO2-enhanced oil recovery and storage well spacing decision method of this invention first considers the change in the oil phase initiation pressure gradient after CO2 injection, and determines a range of technical well spacing by comparing the minimum driving pressure gradient with the crude oil initiation pressure gradient. Second, it uses the curve intersection method to determine the range of economic well spacing. The oil displacement efficiency in the calculation is determined by long core displacement tests, and CO2 recycling needs to be considered. Finally, by utilizing the changes in miscibility and component sweep efficiency, combined with the aforementioned technical and economic well spacing ranges, the final reasonable well spacing is determined. This invention is simple, fast, and the well spacing calculation results are more consistent with actual field conditions.

[0119] For the foregoing method embodiments, in order to simplify the description, they are all described as a series of actions. However, those skilled in the art should understand that the present invention is not limited to the described order of actions, because according to the present invention, some steps can be performed in other orders or simultaneously. Furthermore, those skilled in the art should also understand that the embodiments described in the specification are preferred embodiments, and the actions and modules involved are not necessarily essential to the present invention.

[0120] It should be noted that, in other embodiments of the present invention, the method can also combine one or more of the above embodiments to obtain a new carbon dioxide flooding and storage well spacing decision method, so as to achieve optimized decision-making on the well spacing parameters of the CO2 flooding process.

[0121] It should be noted that, based on the methods in any one or more embodiments of the present invention described above, the present invention also provides a storage medium storing program code that can implement the methods described in any one or more embodiments. When the program code is executed by the operating system, it can implement the carbon dioxide flooding and sealing well spacing decision method as described above.

[0122] Example 2

[0123] The methods described in detail in the above-disclosed embodiments of the present invention can be implemented using various forms of devices or systems. Therefore, based on other aspects of the methods described in any one or more of the above embodiments, the present invention also provides a carbon dioxide flooding and storage well spacing decision system, which is used to execute the carbon dioxide flooding and storage well spacing decision method described in any one or more of the above embodiments. Specific embodiments are given below for detailed description.

[0124] Specifically, Figure 2 The diagram shows a schematic representation of the carbon dioxide flooding and storage well spacing decision system provided in an embodiment of the present invention. Figure 2 As shown, the system includes:

[0125] The viscosity characteristic experiment module is configured to conduct crude oil-CO2 phase experiments in the target reservoir to clarify the viscosity change characteristics of crude oil before and after CO2 injection.

[0126] The starting pressure gradient determination module is configured to calculate the starting pressure gradient based on the crude oil viscosity before gas injection and the minimum crude oil viscosity after gas injection as reflected in the experiment.

[0127] The injection-production well spacing analysis module is configured to calculate the minimum driving pressure gradient under different injection-production well spacings, and combine the starting pressure gradient to obtain the injection-production well spacing before and after gas injection.

[0128] The well spacing intersection analysis module is configured to calculate the economic limit well spacing and the economic optimal well spacing of the target reservoir using the curve intersection method.

[0129] The target well spacing decision module is configured to determine the relationship curves between well spacing and CO2 flooding miscibility and CO2 flooding component sweep efficiency, and select the target well spacing by comprehensively considering the distribution characteristics of injection-production well spacing before and after gas injection, economic limit well spacing, and economic optimal well spacing.

[0130] In an optional embodiment, the startup pressure gradient determination module calculates the startup pressure gradient using the following formula:

[0131]

[0132]

[0133] Among them, G DI1 To initiate the pressure gradient before gas injection, G DI2 The starting pressure gradient after gas injection; K is the reservoir permeability; μ oi The viscosity of the crude oil before gas injection is μ. oco2 This represents the minimum crude oil viscosity after gas injection.

[0134] Furthermore, in one embodiment, the injection-production well spacing analysis module is configured to: use the formation pressure before gas injection, the bottom-hole pressure of the injection well, and the bottom-hole flowing pressure of the production well, combined with the well spacing, to calculate the minimum driving pressure gradient under different injection-production well spacings;

[0135] The minimum driving pressure gradient that is consistent with the starting pressure gradient before and after gas injection is selected respectively, and the well distance corresponding to it is taken as the injection-production well distance before and after gas injection.

[0136] Preferably, in one embodiment, the injection-production well spacing analysis module calculates the minimum driving pressure gradient under different injection-production well spacings using the following formula:

[0137]

[0138] In one embodiment, the well spacing intersection analysis module is configured to: establish a first economic calculation model and a second economic calculation model based on the set oil price and carbon dioxide price, respectively;

[0139] Plot the curves of the changes in values ​​of the first economic calculation model and the second economic calculation model with well network density, respectively. Select the well distance corresponding to the well network density at the intersection of the two curves as the economic limit well distance under the oil price and carbon dioxide price.

[0140] Optionally, in one embodiment, the following first economic operation model is adopted:

[0141] y1=[NE D e -a / s / t]G[(1+i) t -1] / i

[0142] The following second economic operation model is adopted:

[0143] y2 = ASM(1+i) t +ASP[(1+i) t -1] / i

[0144] In the formula, A represents the oil-bearing area, in km². 2 N represents crude oil geological reserves, in tons; E D f represents the oil displacement efficiency; a represents the well pattern index, well / km. 2 i represents the annual loan interest rate, f; P represents the annual maintenance and management cost per well, yuan / well / year; G represents the sales price per ton of oil, yuan / ton; M represents the investment in drilling and surface construction per well, yuan / well; T represents the development evaluation period, years; S represents the well network density, wells / km 2 .

[0145] Preferably, in one embodiment, the well spacing intersection analysis module establishes a third economic calculation model and a fourth economic calculation model based on the set oil price and carbon dioxide price, respectively;

[0146] Plot the curves of the numerical values ​​of the third and fourth economic operation models as a function of well density, and select the well spacing corresponding to the well density at the intersection of the two curves as the economically optimal well spacing under the oil price and carbon dioxide price.

[0147] Furthermore, in one embodiment, the following third economic operation model is adopted:

[0148] y3=[aNG E D / t]{[(1+i) t -1] / i}e -a / s

[0149] The following fourth economic operation model is adopted:

[0150] y4={M(1+i) t +P[(1+i) t -1] / i}AS 2

[0151] In the formula, A represents the oil-bearing area, in km². 2 N represents crude oil geological reserves, in tons; E D f represents the oil displacement efficiency; a represents the well pattern index, well / km. 2 i represents the annual loan interest rate, f; P represents the annual maintenance and management cost + CO2 per well, yuan / well / year; G represents the sales price per ton of oil, yuan / ton; M represents the investment in drilling and surface construction per well, yuan / well; T represents the development evaluation period, years; S represents the well network density, wells / km 2 .

[0152] Optionally, in one embodiment, the target well spacing decision module is configured to: use component numerical simulation technology to simulate and calculate the relationship curves between well spacing and CO2 flooding miscibility, and between well spacing and CO2 flooding component sweep efficiency for the target work area; configure the overlapping intervals of injection and production well spacing before and after gas injection, and the economic limit well spacing and the economic optimal well spacing interval; and then select the well spacing with the largest product of CO2 flooding miscibility and component sweep efficiency from the overlapping intervals as the target well spacing.

[0153] In the carbon dioxide flooding and storage well spacing decision system provided in this embodiment of the invention, each module or unit structure can operate independently or in combination according to the actual data calculation and curve distribution analysis requirements to achieve the corresponding technical effects.

[0154] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should be extended to equivalent substitutions of these features as understood by those skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.

[0155] The phrase "an embodiment" in the specification means that a specific feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Therefore, the phrase "an embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0156] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and variations in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection for this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for determining well spacing in carbon dioxide enhanced oil recovery and storage, characterized in that, The method includes: Step S100: Conduct crude oil-CO2 phase state experiments in the target reservoir to clarify the viscosity change characteristics of crude oil before and after CO2 injection; Step S200: Calculate the starting pressure gradient based on the crude oil viscosity before gas injection and the minimum crude oil viscosity after gas injection as reflected in the experiment; Step S300: Calculate the minimum driving pressure gradient under different injection-production well spacing, and obtain the injection-production well spacing before and after gas injection by combining the starting pressure gradient; Step S400: Calculate the economic limit well spacing and the economic optimal well spacing of the target reservoir using the curve intersection method; Step S500: Determine the relationship curves between well spacing and CO2 flooding miscibility and CO2 flooding component sweep efficiency, and select the target well spacing by comprehensively considering the distribution characteristics of injection-production well spacing before and after gas injection, economic limit well spacing, and economic optimal well spacing.

2. The method according to claim 1, characterized in that, In step S200, the starting pressure gradient is calculated using the following formula: Among them, G DI1 To initiate the pressure gradient before gas injection, G DI2 The starting pressure gradient after gas injection; K is the reservoir permeability; μ oi The viscosity of the crude oil before gas injection is μ. oco2 This represents the minimum crude oil viscosity after gas injection.

3. The method according to claim 1, characterized in that, In step S300, the minimum driving pressure gradient under different injection-production well distances is calculated by using the formation pressure before gas injection, the bottom pressure of the injection well, and the bottom flowing pressure of the production well, combined with the well distance. The minimum driving pressure gradient that is consistent with the starting pressure gradient before and after gas injection is selected respectively, and the well distance corresponding to it is taken as the injection-production well distance before and after gas injection.

4. The method according to claim 1 or 3, characterized in that, In step S300, the minimum driving pressure gradient under different injection-production well spacings is calculated using the following formula:

5. The method according to claim 1, characterized in that, In step S400, based on the set oil price and carbon dioxide price, a first economic calculation model and a second economic calculation model are established respectively. Plot the curves of the changes in values ​​of the first economic calculation model and the second economic calculation model with well network density, respectively. Select the well distance corresponding to the well network density at the intersection of the two curves as the economic limit well distance under the oil price and carbon dioxide price.

6. The method according to claim 5, characterized in that, The following first economic operation model is adopted: y1=[NE D yes -a / s / t]G[(1+i) t -1] / i The following second economic operation model is adopted: y2=ASM(1+i) t +ASP[(1+i) t -1] / i In the formula, A represents the oil-bearing area; y1 and y2 are the first and second indicators for determining the economic limit well density through cross-plotting; N represents the crude oil geological reserves; E D The following values ​​represent the oil displacement efficiency; a represents the well network index; i represents the annual loan interest rate; P represents the annual maintenance and management cost and CO2 total cost per well; G represents the sales price per ton of oil; M represents the investment in drilling and surface construction per well; t represents the development evaluation period; and S represents the well network density.

7. The method according to claim 1, characterized in that, In step S400, based on the set oil price and carbon dioxide price, a third economic operation model and a fourth economic operation model are established respectively. Plot the curves of the numerical values ​​of the third and fourth economic operation models as a function of well density, and select the well spacing corresponding to the well density at the intersection of the two curves as the economically optimal well spacing under the oil price and carbon dioxide price.

8. The method according to claim 7, characterized in that, The following third economic operation model is adopted: y3=[aNG E D / t]{[(1+i) t -1] / i}e -a / s The following fourth economic operation model is adopted: y4={M(1+i) t +P[(1+i) t -1] / i}AS 2 In the formula, A represents the oil-bearing area; y3 and y4 are the third and fourth indicators for determining the economically optimal well density through cross-plotting; N represents the crude oil geological reserves; E D The following values ​​represent the oil displacement efficiency; a represents the well network index; i represents the annual loan interest rate; P represents the annual maintenance and management cost and CO2 total cost per well; G represents the sales price per ton of oil; M represents the investment in drilling and surface construction per well; t represents the development evaluation period; and S represents the well network density.

9. The method according to claim 1, characterized in that, In step S500, using component numerical simulation technology, the relationship curves between well spacing and CO2 flooding miscibility, and between well spacing and CO2 flooding component sweep efficiency are simulated and calculated for the target work area. The overlapping intervals of injection and production well spacing before and after gas injection, and between the economic limit well spacing and the economic optimal well spacing are configured. Then, the well spacing with the largest product of CO2 flooding miscibility and component sweep efficiency is selected from the overlapping intervals as the target well spacing.

10. A storage medium, characterized in that, The storage medium stores program code capable of implementing the method as described in any one of claims 1 to 9.

11. A carbon dioxide enhanced oil recovery and storage well spacing decision system, characterized in that, The system performs the method as described in any one of claims 1 to 9.

Images