Gas injection development scheme optimization method based on carbon dioxide oil displacement
By acquiring production characteristic data and using numerical simulation software to model gas-flooded reservoirs, the parameter optimization problem of the CO2 flooding scheme was solved, the oilfield recovery rate was improved, and the gas injection development plan was optimized.
Patent Information
- Application Number
- CN202410356364.7
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2024-03-27
- Publication Date
- 2025-09-30
AI Technical Summary
In the existing technology, how to quickly obtain a carbon dioxide oil recovery gas injection development plan suitable for the reservoir characteristics of each oil field is an urgent problem to be solved.
By acquiring production characteristic data of the study area, numerical simulation software is used to model gas-drive reservoirs, including establishing grid data fields, tabular data and dynamic models, performing reservoir development history fitting and parameter optimization, and selecting the best gas injection development plan.
A scientific and reasonable carbon dioxide flooding plan was implemented, which improved the recovery rate, effectively guided oil field development, and optimized injection and production parameters and development indicators.
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Figure CN120719965A_ABST
Abstract
Description
Technical Field
[0001] The present invention relates to oil and gas development technology, and in particular to a method for optimizing a gas injection development scheme based on carbon dioxide oil recovery. Background Art
[0002] Carbon dioxide flooding technology is a technology that injects carbon dioxide into oil layers to increase the oil recovery rate of oil fields.
[0003] When CO2 and formation crude oil first come into contact, they are not miscible. However, under the appropriate conditions of pressure, temperature, and crude oil composition, CO2 can form a miscible front. The supercritical fluid extracts heavier hydrocarbons from the crude oil and continuously concentrates the gas at the displacement front. As a result, the CO2 and crude oil become miscible liquids, forming a single liquid phase, which can effectively displace the formation oil to the production well.
[0004] Carbon dioxide recovery technology is now gradually being deployed in various oil fields. Due to the different reservoir properties of each oil field, how to quickly obtain the relevant parameters of the carbon dioxide recovery gas injection development plan is an urgent problem that needs to be solved. Summary of the Invention
[0005] The technical problem to be solved by the present invention is to provide a method for optimizing a gas injection development scheme based on carbon dioxide oil recovery in response to the defects in the prior art.
[0006] The technical solution adopted by the present invention to solve the technical problem is: a method for optimizing a gas injection development scheme based on carbon dioxide oil recovery, comprising the following steps: 1) Obtain production characteristics data for relevant wells using CO2 flooding in the study area and compare and analyze the production characteristics of each well; The relevant production characteristics include dynamic data of production wells, completion data of production wells, pressure data and test data; The dynamic data of the production wells include single-well oil production, liquid production, gas production, water injection volume, oil-gas ratio, and oil-water ratio; the completion data of the production wells include perforation thickness, perforation time, plugging and water plugging, and the time when the plugging layer was put into production; the pressure data includes formation pressure, bottomhole flowing pressure, and wellhead pressure; the test data includes water absorption profile, liquid production profile, RFT pressure measurement (wireline pressure measurement), and acid fracturing data; 2) Based on the reservoir characteristics of the oil region and the actual situation of the oil field, and in view of the characteristics of numerical simulation of gas-drive reservoirs, the general state equation component simulator of the numerical simulation software is selected to carry out gas-drive reservoir modeling; 3) Conduct geological modeling, including establishing grid data fields, tabular data, and dynamic models; Among them, the grid data field is established by using the graphical modeling module of the numerical simulation software and selecting the rectangular coordinate grid system to establish a homogeneous model; Establish tabular data, including equilibrium zone data, fluid high-pressure physical property data and rock data; Establish a dynamic model to build a model of how completion data, production data, pressure data and some control parameters change over time; Among them, completion data includes perforation, plugging, fracturing, water plugging, plugging removal date, layer position, and well index; Production data includes average daily oil production, daily water production, daily water injection, gas-oil ratio, and water cut; Pressure data include bottom hole flowing pressure and formation pressure; 4) Reservoir development history matching includes initialization matching and water cut matching; Reasonable reservoir parameters such as oil-water boundary position, porosity and effective thickness are obtained through initial fitting; The initialization part of the general state equation component simulator integrates geological, well logging and reservoir engineering analysis data to correct the oil-water boundary position, porosity, permeability, and effective thickness parameters. The calculated reserves are in good agreement with the original geological reserves, original formation pressure and other parameters. Water cut fitting includes block water cut fitting and single-well water cut fitting. The block water cut fitting is affected by the relative permeability curve, local permeability, and interlayer connectivity, and the relative permeability curve and local permeability are adjusted when fitting the block water cut. The single-well water cut fitting uses the result visualization and animation graphics tools of the numerical simulation software to draw the oil saturation distribution map and pressure distribution map of the test well group. 5) Based on the final reservoir model, optimize injection and production parameters and predict cyclic water injection development indicators to obtain the optimal gas injection development plan for the test well group; The injection and production parameter optimization includes development mode optimization, gas-water ratio optimization, injection speed optimization, daily liquid production optimization, gas-water alternation cycle optimization and gas injection time optimization.
[0007] The beneficial effects produced by the present invention are: The present invention conducts numerical simulation of carbon dioxide flooding, comprehensively digests and absorbs existing geological research results, well logging interpretation, oil and gas reservoir engineering research materials and data, and uses numerical model software to conduct corresponding reasonable mining method research and development plan optimization research, which can effectively guide and formulate scientific and reasonable water-gas alternating gas injection to enhance oil recovery test plans. BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The present invention will be further described below with reference to the accompanying drawings and embodiments, in which: Figure 1 is a functional flow chart of an embodiment of the present invention; Figure 2 is a grid division diagram of an embodiment of the present invention; Figure 3 This is a diagram of a construction model of a work area according to an embodiment of the present invention; Figure 4 is a relative permeability curve of a working area according to an embodiment of the present invention; Figure 5 is a fitting curve of moisture content in the working area according to an embodiment of the present invention; Figure 6 is a fitting curve of daily oil production in a work area according to an embodiment of the present invention; Figure 7 is a single well water content fitting curve of an embodiment of the present invention; Figure 8 This is an oil saturation distribution diagram of a test well group according to an embodiment of the present invention; Figure 9 This is a cumulative oil quantity diagram of an injection method optimization according to an embodiment of the present invention; Figure 10 This is a cumulative oil quantity diagram for optimizing the gas-water ratio according to an embodiment of the present invention; Figure 11 This is a graph of cumulative oil volume with optimized injection speed according to an embodiment of the present invention; Figure 12 1. Optimized cumulative oil volume graph of daily fluid production according to an embodiment of the present invention; Figure 13 This is a cumulative oil quantity diagram optimized for the gas-water alternation cycle according to an embodiment of the present invention; Figure 14 This is a cumulative oil volume diagram optimized for gas injection time according to an embodiment of the present invention; Figure 15 This is the periodic water injection development index prediction of the embodiment of the present invention. DETAILED DESCRIPTION
[0009] In order to make the purpose, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with the embodiments. It should be understood that the specific embodiments described herein are only used to explain the present invention and are not intended to limit the present invention.
[0010] like Figure 1 As shown, Figure 1 A numerical simulation method for carbon dioxide flooding is provided in an embodiment of the present invention. Includes: reservoir model selection, geological modeling, reservoir development history matching, and optimization steps for gas injection development plans for test well groups; Specifically, for reservoir model selection, based on the reservoir characteristics of the S well area of a certain oil field and the actual situation of the oil field, and in view of the characteristics of numerical simulation of gas-drive reservoirs, a general state equation component simulator of numerical simulation software with fast computing speed was selected to carry out injection parameter optimization and injection scheme prediction research.
[0011] Gas drive reservoirs are prone to gas channeling, so the grid is divided into smaller parts when establishing the geological model; Specifically, geological modeling includes establishing grid data fields, creating tabular data, and establishing dynamic models; A grid data field was established, with the P well group in the S well area as the test area. The graphical modeling module of the numerical simulation software was used to select the rectangular coordinate grid system to establish a homogeneous model. Considering the influence of fractures, the grid was encrypted, with the number of grids in the X and Y directions being 55 and 47 respectively. The grid step size was 10m. The vertical direction was divided into 1 grid, with a total of 2585 nodes. There are 9 oil and water wells in the work area, including 4 oil wells and 5 water wells. The work area scope and model grid division are shown in Figure 2 The construction model is shown in Figure 3 ; The data to be established in the table include equilibrium zone data, high pressure physical property data of fluid and rock data. The relative permeability curve is selected based on the measured relative permeability curve that is close to the average air permeability, average porosity value and ultimate recovery rate of the block. The relative permeability curve of the work area is shown in Figure 4 , comprehensive reservoir data are shown in Table 1 below; Table 1 Comprehensive reservoir data
[0012] Build a dynamic model, including completion data (perforation, plugging, fracturing, water plugging, unplugging date, layer position, well index, etc.), production data (average daily oil production, daily water production, daily water injection, gas-oil ratio and water cut, etc.); pressure data (bottomhole flowing pressure, formation pressure, etc.), and some control parameters; Specifically, the purpose of reservoir development history matching is to make the established calculation model reflect the actual situation. The adjustment process of history matching is to gradually make the model consistent with the actual production and underground conditions of the oil field, including initialization fitting and history fitting, including initialization fitting and water cut fitting. Initialization fitting mainly fits the geological reserves of the entire area and each output area, as well as the original formation pressure of the block. The initialization part of the general state equation component simulator integrates geological, well logging and reservoir engineering analysis data to correct the oil-water boundary position, porosity, permeability, and effective thickness parameters. The calculated reserves are in good agreement with the original geological reserves, original formation pressure and other parameters. The initialization fitting obtains reasonable reservoir parameters such as the oil-water boundary position, porosity, and effective thickness. The actual geological reserves in the work area are 16.46×10 4 t, fitted reserves 16.61×10 4 t, the fitting error is 0.9% (the standard requirement is less than 5%), which meets the fitting accuracy requirements. The fitting results are shown in Table 2 below; Table 2 Geological reserves fitting results
[0013] Water cut fitting is an important part of numerical simulation research of oil and gas reservoirs. This work can help oil and gas reservoir engineers, geological engineers and numerical simulation researchers to re-understand the previously established oil and gas reservoir geological models and fluid physical parameters, laying a solid foundation for future oil and gas reservoir development engineering research and dynamic prediction. Water cut fitting includes block water cut fitting and single well water cut fitting; The block water content fitting is mainly affected by the relative permeability curve, local permeability and interlayer connectivity. When fitting the block water content, the relative permeability curve and local permeability are mainly adjusted. The water content fitting results of the work area are shown in Figure 5 , the daily oil production fitting curve is shown in Figure 6 ,It can be seen from the figure that the production history fitting of the ,work area meets the accuracy requirements; Single well water cut fitting is to use the result visualization and animation graphics tools of numerical simulation software to draw the current water cut fitting curve and oil saturation distribution map of the test well group. Figure 7 、 Figure 8 ; Specifically, the gas injection development plan for the test well group is optimized, including injection and production parameter optimization and cyclic water injection development index prediction; Optimization of injection and production parameters, including development method optimization, gas-water ratio optimization, injection rate optimization, daily liquid production optimization, gas-water alternation cycle optimization and gas injection time optimization.
[0014] Development mode optimization is to select P well group to carry out CO2 gas drive, gas-water alternating drive, gas-water alternating drive + foam drive and conventional water injection to optimize the development mode. The prediction results show that gas injection development is better than water injection development, among which gas-water alternating drive + foam drive can slow down gas channeling and has the best effect. Figure 9 ; The gas-water ratio was optimized and the P well group was selected for gas-water alternating production. The development index predictions were made for five injection methods with gas-water ratios of 1:1, 1:2, 1:3, 2:1, and 3:1. Figure 10 As can be seen from the figure, increasing the gas injection ratio can increase the accumulated oil volume, but the oil-increasing effect gradually slows down. When the gas-water ratio reaches 2:1, the oil-increasing effect is no longer obvious. When it reaches 3:1, gas channeling is serious and the accumulated oil volume is greatly reduced. Taking into account the oil-increasing volume and the injection volume, the gas-water alternation ratio is determined to be 1:1 (underground volume). The injection speed is optimized. The work area adopts the gas-water alternating injection method. The designed injection volume is 0.8 times, 1.0 times, 1.2 times and 1.5 times of the current injection volume for mining. The scheme design is shown in Table 5. Comparing the development effects of different injection speeds, see Figure 11As can be seen from the figure, increasing the injection rate can increase oil production in the early stage (up to 1.5 times), but gas channeling will reduce the oil production effect in the later stage; from the perspective of cumulative oil production, the best effect is achieved when the injection rate remains unchanged. To optimize the daily liquid production, a total of 4 development plans were designed, with 4 oil production wells and 1 injection well selected. The injection rate was based on the current injection rate, and the liquid production was 1.0 times, 1.1 times, 1.2 times, and 1.3 times the current liquid production. The gas-water alternation method was used at a ratio of 1:1. The cumulative oil production effects of different liquid production rates were compared. Figure 12 As can be seen from the figure, increasing the liquid production rate can increase the oil production rate. After reaching 1.1 times, further increasing the liquid production rate will cause gas channeling, which will reduce the oil production effect. To prevent premature gas channeling, the liquid production rate is determined to be around 1.1 times. Gas-water alternation cycle optimization, based on the previous gas injection parameter optimization results, adopts the injection rate as the current injection rate, the liquid production as 1.1 times the current liquid production, and the gas-water ratio as 1:1, and performs gas alternation drive production. Four production methods, including 10 days of gas injection + 20 days of water injection, 15 days of gas injection + 30 days of water injection, 20 days of gas injection + 40 days of water injection, and 30 days of gas injection + 60 days of water injection, are designed for injection cycle optimization. The cumulative oil production effects of different gas-water alternation cycles are compared. Figure 13 As can be seen from the figure, the smaller the slug, the better the injection effect. However, the overall difference in accumulated oil volume is small. Taking into account the field operation conditions, the gas-water alternation cycle is determined to be 15 days of gas injection + 30 days of water injection. Gas injection time optimization, using the previous injection parameter optimization results, according to the 1:1 gas-water ratio, designed 4 gas drive times of 1 year, 2 years, 3 years, and 4 years for gas-water alternating injection, and compared the cumulative oil production effect under different gas injection times. Figure 14 ,As can be seen from the figure, the oil increase effect of the 4th year is poor, so the ,gas injection time is determined to not exceed 3 years; The cyclic waterflooding development indicators are predicted. The test area uses 4 oil production wells and 1 water injection well for alternating CO2 gas and water injection and production. The oil well discharge rate is 1.1 times the current level, the gas injection rate is 8t / d, and the water injection rate is 20m3 / d. After 3 years of injection, water flooding development will be switched. The forecast period is 3 years. By 2026, it is expected that 989t of oil will be added, and the recovery rate will be increased by 0.94%. The water cut will drop by 23 percentage points at most, and the daily oil production will increase by 99.2%. Figure 15 .
[0015] In the description of this specification, reference to the term "one embodiment" or the like means that the specific features, structures, materials, or characteristics described in conjunction with that embodiment or example are included in at least one embodiment or example of the present invention. In this specification, the schematic representations of the above terms do not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in any one or more embodiments or examples. In addition, those skilled in the art may combine and combine different embodiments or examples described in this specification, as well as features of different embodiments or examples, unless they are mutually inconsistent.
[0016] It should be understood that those skilled in the art can make improvements or changes based on the above description, and all such improvements and changes should fall within the scope of protection of the appended claims of the present invention.
Claims
1. A method for optimizing a gas injection development scheme based on carbon dioxide flooding, characterized in that: The following steps are involved: 1) Obtain production characteristics data for relevant wells using CO2 flooding in the study area and compare and analyze the production characteristics of each well; The relevant production characteristics include dynamic data of production wells, completion data of production wells, pressure data and test data; 2) Based on the reservoir characteristics of the oil region and the actual situation of the oil field, and in view of the characteristics of numerical simulation of gas-drive reservoirs, the general state equation component simulator of the numerical simulation software is selected to carry out gas-drive reservoir modeling; 3) Conduct geological modeling, including establishing grid data fields, tabular data, and dynamic models; Among them, the grid data field is established by using the graphical modeling module of the numerical simulation software and selecting the rectangular coordinate grid system to establish a homogeneous model; Establish tabular data, including equilibrium zone data, fluid high-pressure physical property data and rock data; Establish a dynamic model to model the changes of completion data, production data, pressure data and control parameters over time; 4) Perform reservoir development history matching, including initialization matching and water cut matching; Reasonable reservoir parameters such as oil-water boundary position, porosity and effective thickness are obtained through initial fitting; The initialization part of the general state equation component simulator integrates geological, well logging and reservoir engineering analysis data to correct the oil-water boundary position, porosity, permeability, and effective thickness parameters. The calculated reserves are consistent with the original geological reserves and original formation pressure parameters. Water cut fitting includes block water cut fitting and single-well water cut fitting. The block water cut fitting is affected by the relative permeability curve, local permeability, and interlayer connectivity, and the relative permeability curve and local permeability are adjusted when fitting the block water cut. The single-well water cut fitting uses the result visualization and animation graphics tools of the numerical simulation software to draw the oil saturation distribution map and pressure distribution map of the test well group. 5) Based on the final reservoir model, optimize injection and production parameters and predict cyclic water injection development indicators to obtain the optimal gas injection development plan for the test well group; The injection and production parameter optimization includes development mode optimization, gas-water ratio optimization, injection speed optimization, daily liquid production optimization, gas-water alternation cycle optimization and gas injection time optimization.
2. The method for optimizing a gas injection development scheme based on carbon dioxide flooding according to claim 1, characterized in that: In step 1), the dynamic data of the production wells include single-well oil production, liquid production, gas production, water injection rate, oil-gas ratio, and oil-water ratio; the completion data of the production wells include perforation thickness, perforation time, perforation plugging and water plugging, and the time when the plugging layer was put into production; the pressure data includes formation pressure, bottomhole flowing pressure, and wellhead pressure; and the test data includes water absorption profile, liquid production profile, RFT pressure measurement, and acid fracturing data.
3. The method for optimizing a gas injection development scheme based on carbon dioxide flooding according to claim 1, characterized in that: In step 3), the completion data includes perforation, plugging, fracturing, water plugging, unplugging date, layer position, and well index; the production data includes average daily oil production, daily water production, daily water injection, gas-oil ratio, and water cut; and the pressure data includes bottomhole flowing pressure and formation pressure.
4. A server comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein: When the processor executes the computer program, the method according to any one of claims 1 to 3 is implemented.
5. A computer-readable storage medium, characterized in that The computer-readable storage medium stores computer instructions, and the computer instructions are used to enable a processor to implement the method according to any one of claims 1 to 3 when executed.