A method and system for developing a CO2 flooding and storage coordinated method for a bottom water reservoir

Abstract

The application provides a bottom water reservoir CO2 oil displacement and storage coordinated development method and system, which collects information of a target work area, and determines a component numerical simulation model matched with the target work area; determines a plurality of deployment positions of a horizontal injection well in a water layer in combination with water injection well conditions, oil layer thickness and oil-water interface positions of the reservoir, and uses the component numerical simulation model to simulate and calculate the deployment positions of the target injection well in order to optimize oil increment and storage capacity; further sets feasible injection parameters, and uses displacement effect and storage effect as optimization targets to simulate and calculate the injection mode of the target parameters; sets feasible injection and production speed combination schemes according to liquid production before gas injection, and simulates and calculates the injection speed and liquid production speed with the optimal oil increment and storage capacity. The scheme can overcome the problem of incomplete optimization effect in the prior art, effectively plays the energy and capacity of edge and bottom water, and realizes the increase of a large oil increment and the increase of CO2 storage capacity.

Description

Technical Field

[0001] This invention relates to the field of reliability testing and evaluation technology, and in particular to a development method and system for the synergistic development of CO2 flooding and storage in bottom water reservoirs. Background Technology

[0002] Because CO2 flooding can achieve a win-win situation of increasing oil production and reducing carbon emissions, CO2 flooding technology has attracted widespread attention; in recent years, related implementation projects in the petrochemical field have also developed rapidly. Compared with other enhanced oil recovery technologies, CO2 flooding has many advantages; for example, CO2 has the characteristics of extracting light components, reducing crude oil viscosity, expanding crude oil volume, and mixing with crude oil to improve its flowability. To leverage these mechanisms, CO2 flooding mainly employs methods such as continuous gas injection, alternating water-gas injection, gravity displacement, circulating gas injection, and huff-and-puff production. For bottom-water reservoirs, these injection methods are currently the main way to inject CO2 into the oil layer, especially at the top of the oil layer, to create an artificial gas cap by utilizing density differences to increase oilfield production.

[0003] With the evolving requirements of different stages of development in the field, CO2 sequestration has become a focal point, even surpassing oil production growth in some situations. However, the aforementioned injection methods are all geared towards increasing oil production and oil exchange rates, often failing to achieve substantial, high-quality sequestration. Therefore, it is necessary to modify current injection methods to simultaneously increase CO2 sequestration while achieving significant oil production growth. Particularly for edge-bottom water reservoirs, a scientifically sound solution is urgently needed to leverage the energy and capacity of edge-bottom water to enhance both CO2 production growth and sequestration.

[0004] 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

[0005] To address the aforementioned issues, this invention provides a development method and system for synergistic CO2 flooding and storage in bottom-water reservoirs. This approach overcomes the limitations of existing technologies in achieving comprehensive optimization, effectively utilizing the energy and capacity of bottom and edge water to achieve significant oil production increases while simultaneously enhancing CO2 sequestration. The method involves collecting data from the target work area and determining a component numerical simulation model that matches the actual conditions of the target area. It then determines several deployment locations of horizontal injection wells within the water layer based on the reservoir's injection well conditions, reservoir thickness, and oil-water interface location. Using the component numerical simulation model, it optimizes the deployment locations of the target injection wells with oil production and sequestration as optimization objectives. Furthermore, it sets feasible injection parameters and optimizes the injection method based on displacement and sequestration effects. Finally, it sets feasible injection-production rate combinations based on the pre-injection fluid production rate and optimizes the injection and production rates for the optimal oil production and sequestration rates through simulation. Based on this, CO2 is injected from the aquifer using a horizontal well, creating a two-phase flow of gas and water within the aquifer. This reduces the seepage velocity of both gas and water, achieving the same effect as conventional gas-water co-injection. Simultaneously, the CO2 dissolves in the water, increasing the density of the aqueous phase, slowing vertical water migration, and reducing the water cut. Ultimately, a CO2 gas chamber is established within the water body, utilizing the saline water (bottom water) sequestration capability. Preferably, in one embodiment, the method includes:

[0006] Simulation model determination steps: For the target work area, collect its engineering data and determine the component numerical simulation model that matches the actual data of the target work area;

[0007] Well placement determination steps: Based on the water injection well situation of the reservoir, the oil layer thickness and the position of the oil-water interface, determine several deployment positions of horizontal injection wells in the water layer, and use the increase in oil production and the amount of oil stored as optimization targets to simulate and calculate the optimal deployment positions of the target injection wells;

[0008] Injection method determination steps: Based on continuous gas injection and periodic gas injection, feasible injection parameters are set, and the preferred injection method with displacement effect and burial effect as optimization objectives is determined by component numerical simulation method.

[0009] Injection-production rate setting steps: Based on the pre-injection liquid production volume, set a feasible injection-production rate combination scheme, and use component numerical simulation method to select the injection rate and production rate with the optimal oil increase and CO2 storage volume.

[0010] In an optional embodiment, the simulation model determination step employs a component numerical simulation model that matches the geological data and process information of the target work area; the component numerical simulation model is established according to the following logic:

[0011] Collect geological data and process information for the work area, including three-dimensional geological models, historical dynamic data, perforation data, fracturing data, relative permeability data, high-pressure physical property data, and monitoring data;

[0012] A component numerical simulation model is established, and historical fitting is performed based on the geological data and process data to form the target component numerical simulation model.

[0013] Furthermore, in one embodiment, the well location determination step includes the following operations:

[0014] Horizontal deployment steps: Determine the planar deployment location of horizontal injection wells according to the situation of injection wells for different bottom water reservoirs;

[0015] Vertical positioning steps: Select several locations in the water layer as the vertical deployment locations of the horizontal injection wells based on the oil layer thickness and oil-water interface location of the reservoir.

[0016] Injection well location determination steps: Based on the aforementioned planar and vertical deployment locations, multiple injection well simulation schemes are reorganized using an orthogonal design method, and the optimal target location is calculated using component numerical simulation methods with the optimization objectives of increased oil production and storage volume.

[0017] Optionally, in one embodiment, in the horizontal positioning deployment step, for bottom water reservoirs without water injection wells, the planar deployment position of the horizontal injection well is determined to be the middle part of the production well; for bottom water reservoirs with water injection wells, a water injection well of a set size is selected for side-drilling and converted into a horizontal injection well, while the other water injection wells are shut in.

[0018] Furthermore, in one embodiment, during the horizontal positioning deployment step, when selecting a water injection well of a predetermined size, the target water injection well is selected according to the following principles:

[0019] Select one or more water injection wells located in the middle of the reservoir;

[0020] The ratio of the target number of injection wells to the total number of injection wells should be between 1 / 3 and 1 / 2.

[0021] The swept volume of the target injection well after being converted from a side-drilled well to a horizontal injection well is greater than or equal to the swept volume of the original injection-production well network.

[0022] In one embodiment, in the vertical positioning step, several relative distances are set according to the oil layer thickness of the reservoir, and the relative distance below the oil-water interface is determined as the available vertical deployment position for each horizontal injection well, and at the same time as the vertical deployment position for the perforation of the production well.

[0023] Preferably, in one embodiment, in the step of determining the injection method, the injection parameters for the continuous injection method include the injection time; the injection parameters for the periodic injection method include the injection period interval and the periodic injection time, wherein the injection period interval is one month, and the periodic injection time is set to different durations according to requirements.

[0024] Furthermore, in one embodiment, in the injection-production rate setting step, several feasible injection-production rate combination schemes are set with the constraint that the maximum liquid production volume does not exceed the maximum daily liquid production volume in the production history before gas injection and the injection-production ratio does not exceed a set value.

[0025] 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.

[0026] Based on the application of the methods described in any one or more of the above embodiments, the present invention also provides a development system for the coordinated development of CO2 flooding and storage in bottom water reservoirs, which executes the methods described in any one or more of the above embodiments.

[0027] Compared with the closest prior art, the present invention also has the following beneficial effects:

[0028] This invention provides a development method and system for synergistic CO2 flooding and storage in bottom-water reservoirs. The method determines several deployment locations of horizontal injection wells within the water-bearing layer, considering the reservoir's injection well conditions, oil layer thickness, and oil-water interface location. Using a component numerical simulation model, it optimizes the deployment locations of target injection wells with the goals of increasing oil production and preserving reserves. Furthermore, it sets feasible injection parameters, optimizing the injection method based on displacement and preservation effects. Finally, it sets feasible injection-production rate combinations based on pre-injection fluid production, and simulates to optimize the injection and production rates for the best oil production and preservation. This method utilizes horizontal wells to inject CO2 from the water-bearing layer, creating a gas-water two-phase flow within the layer. This reduces the seepage velocity of both gas and water, achieving the effect of conventional gas-water co-injection. Simultaneously, CO2 dissolves in the water, increasing the water phase density, slowing vertical water migration, and reducing water cut. Ultimately, it establishes a CO2 gas cavity within the water body, leveraging the saline (bottom-water) preservation capacity to achieve a significant increase in oil production while simultaneously improving CO2 preservation.

[0029] 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

[0030] 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:

[0031] Figure 1This is a flowchart illustrating a method for the coordinated development of CO2 flooding and storage in bottom water reservoirs, provided in an embodiment of the present invention.

[0032] Figure 2 This is an example diagram showing the distribution of water injection wells before and after sidetracking in the CO2 flooding and storage synergistic development method for bottom water reservoirs provided in this embodiment of the invention.

[0033] Figure 3 This is a schematic diagram of the vertical well deployment of a horizontal well in a bottom water reservoir CO2 flooding and storage synergistic development method provided in an embodiment of the present invention;

[0034] Figure 4 This is a schematic diagram comparing the increase in oil production and the amount of oil stored in the horizontal well water layer injection and the injection into the oil layer in the development method of CO2 flooding and storage synergy in bottom water reservoirs provided in the embodiments of the present invention.

[0035] Figure 5 This is a schematic diagram of the development system for CO2 flooding and storage synergy in bottom water reservoirs provided in another embodiment of the present invention. Detailed Implementation

[0036] 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.

[0037] 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.

[0038] 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.

[0039] 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.

[0040] Because CO2 injection can achieve a win-win situation of increasing oil production and reducing carbon emissions, CO2 injection oil recovery technology has attracted widespread attention; in recent years, related implementation projects in the petrochemical field have also been developing rapidly.

[0041] Compared with other enhanced oil recovery (EOR) technologies, CO2 flooding offers numerous advantages. For instance, CO2 can extract light components, reduce crude oil viscosity, expand crude oil volume, and improve its miscibility and flowability. To leverage these mechanisms, CO2 flooding primarily employs methods such as continuous gas injection, alternating water-gas injection, gravity displacement, circulating gas injection, and huff-and-puff. For bottom-water reservoirs, these injection methods are currently the main approach to inject CO2 into the oil layer, particularly at the top of the oil layer, to utilize density differences to create artificial gas caps and increase oilfield production.

[0042] With the introduction of carbon neutrality and development requirements in the field, CO2 sequestration has become one of the focuses of attention. In some situations, the importance of sequestration even exceeds that of increased oil production. However, the above-mentioned injection methods are all proposed with the goal of increasing oil production and oil replacement rate, and often cannot achieve a large amount of high-quality sequestration.

[0043] Therefore, it is necessary to change the current injection method to increase CO2 sequestration while achieving a greater increase in oil production. Especially for edge-water reservoirs, how to leverage the energy and capacity of edge-water to increase CO2 production and sequestration requires relevant and scientifically sound solutions.

[0044] To address the aforementioned problems, this invention provides a development method and system for synergistic CO2 flooding and storage in bottom-water reservoirs. This method determines the injection well type as a horizontal well and uses component numerical simulation to determine the horizontal well's location in the water body, the injection method, and the injection rate. It also requires the formation pressure to be maintained above 0.8 MPa (the minimum miscibility pressure between CO2 and crude oil). This method fully utilizes the capacity and energy of the water body, organically synergizing the CO2 flooding and storage mechanism, thereby increasing both the oil production and storage capacity from CO2 flooding.

[0045] 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.

[0046] Example 1

[0047] Figure 1 This diagram illustrates a flow chart of the development method for synergistic CO2 flooding and storage in bottom water reservoirs provided in Embodiment 1 of the present invention. (Refer to...) Figure 1 As can be seen, the method includes the following steps.

[0048] Simulation model determination steps: For the target work area, collect its engineering data and determine the component numerical simulation model that matches the actual data of the target work area;

[0049] Well placement determination steps: Based on the water injection well situation of the reservoir, the oil layer thickness and the position of the oil-water interface, determine several deployment positions of horizontal injection wells in the water layer, and use the increase in oil production and the amount of oil stored as optimization targets to simulate and calculate the optimal deployment positions of the target injection wells;

[0050] Injection method determination steps: Based on continuous gas injection and periodic gas injection, feasible injection parameters are set, and the optimal injection method with displacement effect and burial effect is calculated by using component numerical simulation method to simulate and calculate the optimal target parameters.

[0051] Injection-production rate setting steps: Based on the pre-injection liquid production volume, set a feasible injection-production rate combination scheme, and use component numerical simulation method to select the injection rate and production rate with the optimal oil increase and CO2 storage volume.

[0052] Using the method in this embodiment of the invention, CO2 is injected from the water layer through a horizontal well, forming a gas-water two-phase flow in the water layer. This reduces the seepage rate of gas and water, achieving the effect of conventional gas-water co-injection. At the same time, CO2 dissolves in the water, increasing the density of the water phase, slowing down the vertical migration of water, and reducing the water cut. Ultimately, a CO2 gas cavity is established in the water body, leveraging the saline water (bottom water) sealing capacity. This effectively and organically combines oil displacement and storage optimization, improving the development effect of CO2 flooding and increasing the amount of CO2 stored.

[0053] Preferably, in one embodiment, in the simulation model determination step, data on the target work area are collected, especially a component numerical simulation model that conforms to the actual reservoir.

[0054] The component numerical simulation model adopts the reservoir numerical simulation calculation model corresponding to the geological data and process data of the target work area. In actual application, if there is already a historically fitted component numerical simulation model in the actual work area, the corresponding component numerical simulation model is directly used to realize the simulation calculation.

[0055] If no historically fitted component numerical simulation model exists for the actual work area, construct the corresponding component numerical simulation model for the work area according to the following logic:

[0056] Collect geological data and process information for the work area, including three-dimensional geological models, historical dynamic data, perforation data, fracturing data, relative permeability data, high-pressure physical property data, and monitoring data (such as tracer data);

[0057] A component numerical simulation model is established and historical data fitting is performed to form a usable component numerical simulation model for subsequent applications. Essentially, a reservoir component numerical simulation model is a data volume.

[0058] Next, by combining the well placement steps with the water injection well situation, oil layer thickness and oil-water interface position of the reservoir, several deployment positions of horizontal injection wells in the water layer are determined, and the target injection well deployment positions are optimized by simulation calculation with the increase in oil production and the amount of oil stored as optimization objectives.

[0059] In a preferred embodiment, the well location determination step includes the following operations:

[0060] Horizontal deployment steps: Determine the planar deployment location of horizontal injection wells according to the situation of injection wells for different bottom water reservoirs;

[0061] Vertical positioning steps: Select several locations in the water layer as the vertical deployment locations of the horizontal injection wells based on the oil layer thickness and oil-water interface location of the reservoir.

[0062] Injection well location determination steps: Based on the aforementioned planar and vertical deployment locations, multiple injection well simulation schemes are reorganized using an orthogonal design method, and the optimal target location is calculated using component numerical simulation methods with the optimization objectives of increased oil production and storage volume.

[0063] Specifically, in an optional embodiment, in the horizontal deployment step, for bottom water reservoirs without injection wells, the planar deployment position of the horizontal injection well is determined to be the middle part of the production well; for bottom water reservoirs with injection wells, a set size of injection wells is selected for side-drilling and converted into horizontal injection wells, while the other injection wells are shut in.

[0064] In practical applications, the planar location of the injection well is set according to the following principles:

[0065] (1) For strong bottom water reservoirs without water injection wells, horizontal injection wells are deployed in the middle of the production wells; the number of horizontal wells deployed is usually determined according to the actual size of the reservoir and the number of wells.

[0066] (2) For bottom water reservoirs with injection wells, select the target injection well, shut off the other injection wells except the target injection well, and side-drill the target injection well to convert it into a horizontal injection well.

[0067] In selecting target injection wells, the following principles should be followed: 1) Select one or more injection wells located in the central part of the reservoir; 2) The number of target injection wells should account for 1 / 3 to 1 / 2 of the total number of original injection wells; 3) The swept volume after the target injection wells are converted from sidetracked to horizontal injection wells should meet the set requirements. Typically, newly formed horizontal wells can achieve the same or even higher swept volume compared to the original injection-production well network. Figure 2 As shown in the figure, red dots represent oil wells and blue dots represent water wells.

[0068] In another optional embodiment, in the vertical position setting step, several relative distances are set according to the oil layer thickness of the reservoir, and the relative distance below the oil-water interface is determined as the available vertical deployment position for each horizontal injection well, and at the same time as the vertical deployment position for the perforation of the production well.

[0069] In this embodiment of the invention, during the process of determining the vertical position of the injection well and the perforation position of the production well, all injection wells are deployed in the water body, that is, CO2 is injected from the water layer; specifically, in an optional embodiment, according to the oil layer thickness h, each injection horizontal well is deployed at a depth of 0.5h, 1.0h, 2h and 3h below the oil-water interface, forming a variety of feasible vertical deployment schemes.

[0070] Furthermore, in the step of determining the location of the injection well, in practical applications, the horizontal and vertical deployment location schemes are reorganized according to the orthogonal design method to form multiple simulation schemes. The component numerical simulation method is then used to simulate and calculate the optimal location of the horizontal injection well in the water body with the increase in oil production and the amount of oil stored as optimization objectives.

[0071] In an optional embodiment, during the simulation calculation, the formation pressure is maintained at a set level; based on the minimum miscibility pressure of the work area determined by indoor experiments, the formation pressure is required to be maintained at 0.8 times higher than the minimum miscibility pressure. On this basis, the simulation calculation is stably achieved, and based on the regulations of relevant oil and petrochemical enterprises, it is predicted that the calculated gas-oil production ratio will reach the set conditions, such as 3000m³, within 10 or 15 years. 3 / m 3 The corresponding simulation scheme is taken as the optimal scheme, and the optimal location of the horizontal injection well is obtained based on this.

[0072] During the simulation, the formation pressure is monitored in real time. When the average reservoir pressure falls below 0.8 MPa, the injection-production ratio needs to be adjusted (increasing the injection rate appropriately while controlling the production rate) to improve the average formation pressure. Next, the injection mode determination step is performed. Feasible injection parameters are set based on continuous and periodic gas injection modes. The optimal injection mode with the displacement and burial effects as optimization objectives is calculated using component numerical simulation methods.

[0073] In the step of determining the injection method, the injection parameters for the continuous injection method include the injection time; the injection parameters for the periodic injection method include the injection period interval and the periodic injection time. The injection period interval is one month, and the periodic injection time is set to different durations according to the requirements.

[0074] In practical applications, the displacement and storage effects of continuous gas injection and periodic gas injection are compared using component numerical simulation methods. The periodic injection time can be set to 2 months, 3 months, 4 months, and 5 months; that is, the periodic injection scheme is generally set to inject for 2 months and stop for 1 month, inject for 3 months and stop for 1 month, inject for 4 months and stop for 1 month, and inject for 5 months and stop for 1 month. During the simulation, different injection methods can be simulated by modifying the injection-production well control part in the component numerical simulation model.

[0075] Further, the injection-production rate setting step is executed. Based on the liquid production volume before gas injection, a feasible injection-production rate combination scheme is set. The optimal injection rate and liquid production rate for increasing oil production and CO2 storage volume are selected using component numerical simulation methods.

[0076] In a preferred embodiment, in the injection-production rate setting step, several feasible injection-production rate combination schemes are set with the constraint that the maximum liquid production volume does not exceed the maximum daily liquid production volume in the production history before gas injection and the injection-production ratio does not exceed a set value.

[0077] In practical applications, the process of determining the injection rate of injection wells and the production rate of production wells involves using component numerical simulation methods to compare the increased oil production and CO2 accumulation of different combinations of injection and production rates to determine the optimal injection and production rates. The injection and production rate schemes are set with reference to the daily production volume before gas injection, with the maximum production volume set not exceeding the maximum production volume in the production history before gas injection, and the injection-production ratio not exceeding 1.1.

[0078] In a preferred embodiment, the method further includes a prediction calculation verification step: predicting the oil displacement effect and the amount of oil buried in the work area by CO2 injection.

[0079] During the prediction calculation process, numerical simulation calculations are performed using the aforementioned component numerical simulation model to obtain the oil production, gas production, water production, and gas injection data of the optimized scheme. The comparative data used as a reference are mainly obtained from the component numerical simulation of the original scheme. Based on the unoptimized original scheme, numerical simulation calculations are performed using the component numerical simulation model to obtain the oil production, gas production, water production, and gas injection data of the unoptimized original scheme. By comparing the oil production, gas production, water production, and gas injection data of the optimized scheme with the oil production, gas production, and gas injection data predicted by the numerical simulation of the unoptimized original scheme, the data on the increase in oil production and changes in the burial volume can be obtained.

[0080] The present invention will be further described below with reference to specific embodiments. The scope of the present invention is not limited to the embodiments, but is defined in the claims.

[0081] Taking Oilfield A as an example, this block is a strong bottom-water reservoir, with the water volume exceeding 200 times the reservoir volume. The reservoir permeability is 200 mD, and the oil layer thickness is 10 m. No water injection development has been implemented; it is currently using bottom-water drive. The current water cut is 80%, with some wells exceeding 95%. Some wells face shut-in issues. Based on the actual conditions of the work area, a CO2-assisted oil recovery and storage scheme is studied:

[0082] (1) Data collection

[0083] Collect data on the target work area, especially numerical simulation models of components that are consistent with the actual reservoir conditions.

[0084] (2) Planar location scheme for injection wells

[0085] This work area is a strong bottom water reservoir with no water injection wells, and is undergoing continuous depletion development. A test well group will be selected, and a new horizontal well will be drilled in the middle of the group as an injection well.

[0086] (3) Scheme setting of injection well in vertical position

[0087] Based on an oil layer thickness of h = 10m, the newly designed horizontal water injection wells are set at locations 0.5h = 5m, 1h = 10m, 2h = 20m, 3h = 30m, and 4h = 40m below the oil-water interface. (See...) Figure 3 As shown.

[0088] (4) Determine the injection well location

[0089] Based on the distribution range of vertical and horizontal well locations, six schemes were set up for numerical simulation studies to determine that the horizontal well's planar position was at the center of the test well group, and the vertical position was at 2h = 20m below the oil-water interface. The six schemes here are the original scheme and the five schemes set in step (3).

[0090] (5) Determine the formation pressure level

[0091] This work area is a strong bottom water reservoir. The formation pressure has not decreased much during the depletion development process and is still higher than the minimum miscibility pressure of 36 MPa, which can meet the design requirements.

[0092] (6) Determination of injection method

[0093] The simulation results showed that the production effect was best when the injection method was set to continuous injection and periodic injection respectively, with 4 months of injection and 1 month of shutdown.

[0094] (7) The injection and collection system is determined.

[0095] The oil production and CO2 accumulation were compared using component numerical simulation methods for different combinations of injection and production rates. Since this work area is a strong bottom water reservoir, the study indicates that production wells will continue to produce at the original production rate, i.e., 110 m³ / day per well. 3 The optimal injection rate is 80 tons / day.

[0096] (8) Predict the oil displacement effect and burial volume of CO2 injection.

[0097] The effect of CO2 injection on oil recovery in the work area was predicted using component numerical simulation technology. The results showed that compared with injecting CO2 into the oil layer, injecting CO2 into the water layer significantly increased both the burial volume and the oil yield. (See figure) Figure 4 In the diagram, the left column represents horizontal well injection into a water layer, and the right column represents horizontal well injection into an oil layer.

[0098] 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.

[0099] 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 development method for the synergistic development of CO2 flooding and storage in bottom water reservoirs, so as to achieve high-quality optimization of the CO2 flooding process in reservoirs.

[0100] 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 realize the development method of CO2 flooding and burial synergy in bottom water reservoirs as described above.

[0101] The methods described in the above-disclosed embodiments of the present invention are detailed. These methods can be implemented using various forms of apparatus 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 development system for the synergistic development of CO2 flooding and storage in bottom-water reservoirs. This system is used to execute the synergistic development method for CO2 flooding and storage in bottom-water reservoirs described in any one or more of the above embodiments. Specific embodiments are given below for detailed description.

[0102] Specifically, Figure 5 The diagram shows a schematic representation of the development system for CO2-assisted oil recovery and storage in bottom-water reservoirs provided in an embodiment of the present invention. Figure 5 As shown, the system includes:

[0103] The simulation model determination module is configured to collect engineering data for the target work area and determine a component numerical simulation model that matches the actual data of the target work area.

[0104] The well location determination module is configured to determine several deployment locations of horizontal injection wells in the water layer by combining the water injection well situation of the reservoir, the oil layer thickness and the position of the oil-water interface, and to optimize the target injection well deployment location by simulation calculation with the oil increase and storage volume as optimization objectives.

[0105] The injection mode determination module is configured to set feasible injection parameters based on continuous gas injection mode and periodic gas injection mode, and use component numerical simulation method to simulate and determine the preferred injection mode with displacement effect and burial effect as optimization objectives.

[0106] The injection-production rate setting module is configured to set feasible injection-production rate combination schemes based on the pre-injection liquid production volume, and to optimize the injection rate and production rate with the best oil increase and CO2 storage volume using component numerical simulation methods.

[0107] In an optional embodiment, the simulation model determination module adopts a component numerical simulation model that matches the geological data and process data of the target work area;

[0108] The simulation model determination module establishes the component numerical simulation model according to the following logic:

[0109] Collect geological data and process information for the work area, including three-dimensional geological models, historical dynamic data, perforation data, fracturing data, relative permeability data, high-pressure physical property data, and monitoring data;

[0110] A component numerical simulation model is established, and historical fitting is performed based on the geological data and process data to form the target component numerical simulation model.

[0111] Furthermore, in one embodiment, the well location determination module includes:

[0112] The horizontal positioning deployment unit is configured to determine the planar deployment position of the horizontal injection wells according to the water injection well situation for different bottom water reservoirs;

[0113] The vertical positioning unit is configured to select several locations in the water layer as the vertical deployment locations of the horizontal injection well based on the oil layer thickness and oil-water interface location of the reservoir.

[0114] The injection well location determination unit is configured to reorganize multiple injection well simulation schemes based on the planar and vertical deployment locations using an orthogonal design method, and to use component numerical simulation methods to simulate and calculate the optimal target location with the oil increase and storage volume as optimization objectives.

[0115] Optionally, in one embodiment, the horizontal positioning deployment unit is configured such that, for bottom water reservoirs without injection wells, the planar deployment position of the horizontal injection well is determined to be the middle part of the production well; for bottom water reservoirs with injection wells, a set size of injection wells is selected for sidetracking and converted into horizontal injection wells, while other injection wells are shut in.

[0116] Furthermore, in one embodiment, the horizontal positioning deployment unit is configured to select target injection wells according to the following principles:

[0117] Select one or more water injection wells located in the middle of the reservoir;

[0118] The ratio of the target number of injection wells to the total number of injection wells should be between 1 / 3 and 1 / 2.

[0119] The swept volume of the target injection well after being converted from a side-drilled well to a horizontal injection well is greater than or equal to the swept volume of the original injection-production well network.

[0120] In one embodiment, the vertical position setting unit is configured to set several relative distances based on the oil layer thickness of the reservoir, and determine the relative distance below the oil-water interface as the available vertical deployment position for each horizontal injection well, and at the same time as the vertical deployment position for the perforation of the production well.

[0121] Preferably, in one embodiment, the injection method determination module sets the injection parameters for continuous injection method including injection time; the injection parameters for periodic injection method include injection period interval and periodic injection time, wherein the injection period interval is one month, and the periodic injection time is set to different durations according to requirements.

[0122] Furthermore, in one embodiment, the injection-production rate setting module is configured to set several feasible injection-production rate combinations with the constraint that the maximum liquid production volume does not exceed the maximum daily liquid production volume in the production history before gas injection and the injection-production ratio does not exceed a set value.

[0123] The development system for CO2 flooding and storage synergy in bottom water reservoirs provided in this embodiment of the invention allows each module or unit structure to operate independently or in combination according to actual parameter settings and simulation calculation requirements, so as to achieve the corresponding technical effects.

[0124] 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.

[0125] 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.

[0126] 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 development method for synergistic CO2 flooding and oil storage in bottom-water reservoirs, characterized in that, The method includes: Simulation model determination steps: For the target work area, collect its engineering data and determine the component numerical simulation model that matches the actual data of the target work area; Well placement determination steps: Based on the water injection well situation of the reservoir, the oil layer thickness and the position of the oil-water interface, determine several deployment positions of horizontal injection wells in the water layer, and use the increase in oil production and the amount of oil stored as optimization targets to simulate and calculate the optimal deployment positions of the target injection wells; Injection method determination steps: Based on continuous gas injection and periodic gas injection, feasible injection parameters are set, and the preferred injection method with displacement effect and burial effect as optimization objectives is determined by component numerical simulation method. Injection-production rate setting steps: Based on the pre-injection liquid production volume, set a feasible injection-production rate combination scheme, and use component numerical simulation method to select the injection rate and production rate with the optimal oil increase and CO2 storage volume.

2. The method according to claim 1, characterized in that, In the simulation model determination step, a component numerical simulation model matching the geological data and process data of the target work area is adopted; the component numerical simulation model is established according to the following logic: Collect geological data and process information for the work area, including three-dimensional geological models, historical dynamic data, perforation data, fracturing data, relative permeability data, high-pressure physical property data, and monitoring data; A component numerical simulation model is established, and historical fitting is performed based on the geological data and process data to form the target component numerical simulation model.

3. The method according to claim 1, characterized in that, The steps for determining the location of wells include the following operations: Horizontal deployment steps: Determine the planar deployment location of horizontal injection wells according to the situation of injection wells for different bottom water reservoirs; Vertical positioning steps: Select several locations in the water layer as the vertical deployment locations of the horizontal injection wells based on the oil layer thickness and oil-water interface location of the reservoir. Injection well location determination steps: Based on the aforementioned planar and vertical deployment locations, multiple injection well simulation schemes are reorganized using an orthogonal design method, and the optimal target location is calculated using component numerical simulation methods with the optimization objectives of increased oil production and storage volume.

4. The method according to claim 3, characterized in that, In the horizontal positioning deployment step, for bottom water reservoirs without water injection wells, the horizontal injection well is positioned in the middle of the production wells; for bottom water reservoirs with water injection wells, a water injection well of a set size is selected for sidetracking and converted into a horizontal injection well, while the other water injection wells are shut in.

5. The method according to claim 3, characterized in that, In the horizontal deployment step, when selecting a water injection well of a set size, the target water injection well should be selected according to the following principles: Select one or more water injection wells located in the middle of the reservoir; The ratio of the target number of injection wells to the total number of injection wells should be between 1 / 3 and 1 / 2. The swept volume of the target injection well after being converted from a side-drilled well to a horizontal injection well is greater than or equal to the swept volume of the original injection-production well network.

6. The method according to claim 3, characterized in that, In the vertical positioning step, several relative distances are set according to the oil layer thickness of the reservoir. The relative distance below the oil-water interface is determined as the available vertical deployment position for each horizontal injection well, and at the same time as the vertical deployment position for the perforation of the production well.

7. The method according to claim 1, characterized in that, In the step of determining the injection method, the injection parameters for the continuous injection method include the injection time; the injection parameters for the periodic injection method include the injection period interval and the periodic injection time. The injection period interval is one month, and the periodic injection time is set to different durations according to the requirements.

8. The method according to claim 1, characterized in that, In the step of setting the injection-production rate, several feasible injection-production rate combination schemes are set with the constraint that the maximum liquid production volume should not exceed the maximum daily liquid production volume in the production history before gas injection and the injection-production ratio should not exceed the set value.

9. A storage medium, characterized in that, The storage medium stores program code that can implement the method as described in any one of claims 1 to 8.

10. A development system for synergistic CO2 flooding and storage in bottom-water oil reservoirs, characterized in that, The system performs the method as described in any one of claims 1 to 8.

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