Method for determining the opening time of a well in a low-permeability reservoir using carbon dioxide miscible flooding

Abstract

This invention relates to a method for determining the well start-up time of carbon dioxide miscible flooding wells in low-permeability reservoirs, belonging to the field of oil and gas exploration and development. The method includes the following steps: 1) using a numerical model of carbon dioxide miscible flooding for the target reservoir, calculating the cumulative oil production, stable production time, and degree of miscibility at different multiples of the minimum miscibility pressure when starting the well; 2) determining the well start-up time by comprehensively considering the changes in cumulative oil production with formation pressure, stable production time with formation pressure, and degree of miscibility with formation pressure. This invention provides a highly accurate, simple, rapid, and economical method for determining the well start-up time of carbon dioxide miscible flooding wells in low-permeability reservoirs, offering a scientific basis for the rational and effective development of carbon dioxide miscible flooding in these reservoirs.

Description

Technical Field

[0001] This invention relates to a method for determining the well opening time of a carbon dioxide miscible flooding well in a low-permeability reservoir, belonging to the field of oil and gas exploration and development. Background Technology

[0002] For the prevalent low-permeability and ultra-low-permeability reservoirs in my country, gas drive is a commonly used method to enhance oil recovery. Based on different displacement principles, gas drive can be divided into miscible and immiscible drive. Theory and experiments show that miscible drive is far more efficient than immiscible drive. Among numerous displacing agents, carbon dioxide has an ultra-low critical temperature and pressure, easily forming a miscible phase under displacement conditions. It also possesses the advantages of being readily available and recoverable. Therefore, carbon dioxide drive technology for enhancing oil recovery in low-permeability reservoirs has become a widely used tertiary oil recovery technology. The minimum miscibility pressure is a key parameter for assessing the feasibility of carbon dioxide drive; miscible drive can only be achieved when the reservoir formation pressure reaches the minimum miscibility pressure. Experiments show that after carbon dioxide injection, the formation pressure begins to rise. Once the formation pressure reaches the minimum miscibility pressure, crude oil and carbon dioxide begin to miscible. As the formation pressure increases, the degree of miscibility gradually improves. Different well opening times significantly affect the degree of miscibility, stable production time, and cumulative oil production. Therefore, accurately determining the well opening time for carbon dioxide miscible drive wells is crucial.

[0003] Currently, there are many research methods and technologies on the miscibility pressure of carbon dioxide flooding both domestically and internationally. These mainly rely on experimental methods, empirical formulas, and numerical simulations to improve the prediction accuracy of minimum miscibility pressure. For example, Zhao Fenglan et al., in their paper "Determination of Minimum Miscibility Pressure of CO2 in Low-Permeability Reservoirs by Core Displacement Experiment" (Oilfield Chemistry, 2018, 35(4):665-670), disclosed a core displacement experimental method for determining minimum miscibility pressure based on indoor reservoir physical simulation and core experiments. Li Ding, in his paper "Simulation Prediction of Minimum Miscibility Pressure of CO2 and Crude Oil System" (Master's Thesis, Shandong University, May 2020), mainly applied four types of machine learning-based models to predict the minimum miscibility pressure. Two methods were used to predict minimum miscibility pressure: one was the prediction of miscibility pressure using molecular dynamics, and the other was a minimum miscibility pressure prediction model. The microscopic mechanism of using alcohols to reduce minimum miscibility pressure was explored. Zhao Yuejun et al., in "Study on Minimum Miscibility Pressure of Supercritical Carbon Dioxide and Crude Oil System under Reservoir Conditions" (Journal of Dalian University of Technology, 2017, 57(2):119-125), studied the prediction of minimum miscibility pressure of carbon dioxide and crude oil system under reservoir conditions using long-slender tube displacement experiments and various empirical formulas. These methods all improve the accuracy of minimum miscibility pressure by changing the method of predicting minimum miscibility pressure, but they do not provide a qualitative or quantitative description of the well opening time. For example, Chinese invention patent application CN111734408A discloses a method for determining the minimum miscibility pressure during the screening stage of carbon dioxide flooding reservoirs in the Ordos Basin. This method mainly establishes a model curve equation for the minimum miscibility pressure versus reservoir temperature: MMP=a / (1+b×exp(-c×T)), where MMP is the minimum miscibility pressure in MPa; a, b, and c are function constants; and T is the reservoir temperature in °C. By substituting existing minimum miscibility pressure data and temperatures from capillary experiments of different reservoirs into the step curve equation and fitting the function constants a, b, and c, the curve equation for the minimum miscibility pressure versus reservoir temperature can be obtained. The minimum miscibility pressure corresponding to the curve equation obtained from the reservoir temperature of the screened reservoir is then determined. Patent application CN105401926A discloses a method for predicting the miscibility pressure of carbon dioxide-driven oil reservoirs. It primarily uses the original formation pressure as a trial pressure value and calculates the carbon dioxide density at different reservoir temperatures under varying formation pressures to determine the minimum miscibility pressure. These patent documents also fail to provide a qualitative or quantitative description of well opening time. Summary of the Invention

[0004] The purpose of this invention is to provide a method for determining the well opening time of a carbon dioxide miscible flooding well in a low-permeability reservoir, which can accurately determine the well opening time of a carbon dioxide miscible flooding well.

[0005] To achieve the above objectives, the technical solution adopted by this invention is as follows:

[0006] A method for determining the well start-up time of a carbon dioxide miscible flooding well in a low-permeability reservoir includes the following steps:

[0007] 1) Using the carbon dioxide miscibility flooding numerical model of the target sand group in the low-permeability reservoir, the cumulative oil production, stable production time and degree of miscibility were calculated when the formation pressure reached different multiples of the minimum miscibility pressure value during well opening.

[0008] 2) Determine the well opening time by comprehensively considering the changes in cumulative oil production with well opening formation pressure, the stable production time with well opening formation pressure, and the degree of miscibility with well opening formation pressure.

[0009] The present invention provides a method for determining the well opening time of carbon dioxide miscible flooding wells in low-permeability reservoirs. This method utilizes numerical simulation technology to accurately simulate the oil and gas reservoir development process. It precisely characterizes the miscibility of carbon dioxide and crude oil from three aspects: cumulative oil production, stable production time, and miscibility. It features high accuracy, simplicity, speed, and economy, and can provide a scientific basis for the rational and effective development of carbon dioxide miscible flooding in low-permeability reservoirs.

[0010] It is understandable that the cumulative oil production, stable production time, and miscibility degree when wells are opened at different multiples of the minimum miscibility pressure can be obtained by establishing a carbon dioxide miscibility flooding numerical model of the target reservoir using reservoir dynamic simulation software, and then inputting the corresponding formation pressure at the time of well opening into the software. The reservoir dynamic simulation software can be Navigator or other commonly used reservoir dynamic simulation software in this field. The carbon dioxide miscibility model is established using geological and development data of the target reservoir. The geological and development data used include reservoir depth, formation pressure, pressure coefficient, porosity, permeability, effective thickness, original gas-oil ratio, underground crude oil density, degassed crude oil density, volume factor, surface crude oil viscosity, oil saturation, saturation pressure, perforation data, well production operating regime, gas injection rate, and gas injection volume.

[0011] Furthermore, among the different multiples, the smallest multiple is no higher than 0.7 times, and the largest multiple is no lower than 1.5 times.

[0012] Furthermore, the different multiples include 0.7 times, 0.8 times, 0.9 times, 1.0 times, 1.1 times, 1.2 times, 1.3 times, 1.4 times and 1.5 times.

[0013] Further, in step 2), the method for determining the well opening time includes the following steps: determining the well opening formation pressure when the increase in cumulative oil production slows down based on the change in cumulative oil production with the well opening formation pressure; determining the well opening formation pressure when the increase in stable production time slows down based on the change in stable production time with the well opening formation pressure; determining the well opening formation pressure when the miscibility tends to stabilize based on the change in miscibility with the well opening formation pressure; finding the intersection of the three well opening formation pressures to determine the well opening formation pressure, and then determining the well opening time.

[0014] Furthermore, the method for determining the well opening pressure of oil wells where the rate of increase in cumulative oil production slows down is as follows: When arranging all well opening pressures from low to high, obtain the difference R between the cumulative oil production corresponding to the higher well opening pressure and the oil production corresponding to the lower well opening pressure in any two adjacent wells, and then select all wells that satisfy R ≤ 0.01 × 10⁻⁶. 4 The well opening pressure t is used for comparison as the well opening pressure when the cumulative oil production increase is slow.

[0015] The method for determining the well opening pressure of oil wells where the rate of increase in stable production time slows down is as follows: when arranging the well opening pressures from low to high, obtain the difference T between the stable production time corresponding to the larger well opening pressure and the stable production time in months corresponding to the smaller well opening pressure among any two adjacent well opening pressures, and use all well opening pressures that satisfy 0 months ≤ T ≤ 2 months as the well opening pressures used for comparison when the rate of increase in stable production time slows down.

[0016] The method for determining the well opening pressure of an oil well with a stable degree of miscibility is as follows: calculate the ratio of the degree of miscibility corresponding to each well opening pressure to the degree of miscibility corresponding to the minimum miscibility pressure. When arranging all the calculated ratios from smallest to largest, obtain the quotient of the larger of any two adjacent ratios divided by the smaller of any two adjacent ratios. The well opening pressures corresponding to the two adjacent ratios used for calculation that satisfy the quotient ≤ 1.12 are taken as the well opening pressures of an oil well with a stable degree of miscibility. Attached Figure Description

[0017] Figure 1 This is a flowchart illustrating the method for determining the well opening time of a carbon dioxide miscible flooding well in a low-permeability reservoir, as described in an embodiment of the present invention.

[0018] Figure 2 This is a graph showing the cumulative oil production variation of carbon dioxide miscible flooding at different well opening times in reservoir A in the example;

[0019] Figure 3 This is a graph showing the variation of stable production time for carbon dioxide miscible flooding at different well opening times in reservoir A in the example;

[0020] Figure 4 This is a graph showing the variation in the degree of miscibility of carbon dioxide miscible flooding at different well opening times in reservoir A in the example. Detailed Implementation

[0021] The technical solution of this invention will be further explained below using the B sandstone group of reservoir A as an example. The B sandstone group of reservoir A is a low-permeability reservoir with a depth of 3200 meters, a porosity of 13.6%, a permeability of 10.6 mD, a lithology of siltstone, a total mineralization of 103000 mg / L, an original formation pressure of 45.7 MPa, and a formation temperature of 108℃. The minimum miscibility pressure of the B sandstone group in reservoir A, measured using the interfacial tension method, is 24.5 MPa.

[0022] Example 1

[0023] The method for determining the well start-up time of a carbon dioxide miscible flooding well in a low-permeability reservoir in this embodiment is as follows: Figure 1 As shown, it includes the following steps:

[0024] 1) A numerical model of carbon dioxide miscible flooding for reservoir A and sand group B was established in the reservoir dynamic simulation software tNavigator using geological and development data of reservoir A and sand group B. The geological and development data used specifically include reservoir depth, formation pressure, pressure coefficient, porosity, permeability, effective thickness, original gas-oil ratio, underground crude oil density, degassed crude oil density, volume factor, surface crude oil viscosity, oil saturation, saturation pressure, perforation data, well production operating system, gas injection rate and gas injection volume.

[0025] 2) Wells in reservoir A, sand group B, were opened at formation pressures of 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, and 1.5 times the minimum miscibility pressure. Then, in the reservoir dynamic simulation software tNavigator, each set formation pressure was input, and the established carbon dioxide miscibility flooding numerical model was used to calculate the cumulative oil production, stable production time, and miscibility degree at the corresponding formation pressures. The miscibility degree was represented by the number of grid cells when the oil saturation was 0. Table 1 shows the cumulative oil production and stable production time at different formation pressures. The miscibility degree (D) at different formation pressures and the miscibility degree (D) at the minimum miscibility pressure are also compared. p The ratio of D / D p See Table 1.

[0026] Table 1 Cumulative oil production, time to stable production, and degree of miscibility

[0027]

[0028] 3) Based on the cumulative oil production obtained in step 2) during well opening under various set formation pressures, plot as follows: Figure 2The graph showing the cumulative oil production variation of carbon dioxide miscible flooding at different well opening times clarifies that the well opening time when the cumulative oil production increase of sand group B in reservoir A slows down is when the formation pressure reaches 1.2 times and 1.3 times the minimum miscible pressure.

[0029] Based on the stable production time obtained in step 2) when opening the well under various set formation pressures, plot as follows: Figure 3 The graph showing the variation of stable production time for carbon dioxide miscible flooding at different well opening times clarifies that the well opening time when the increase in stable production time of sand group B in reservoir A slows down is when the formation pressure reaches 1.3 times and 1.4 times the minimum miscible pressure.

[0030] Based on the miscibility obtained in step 2) during well opening under various set formation pressures, plot as follows: Figure 4 The graph shows the variation of miscibility of carbon dioxide miscible flooding at different well opening times (D / D is the ratio of the miscibility at different well opening times to the miscibility at the minimum miscibility pressure at well opening). p The change indicates that the well opening time when the miscibility of sand group B in reservoir A tends to be stable is when the formation pressure reaches 1.3 times and 1.4 times the minimum miscibility pressure.

[0031] 4) Based on the well opening times determined in step 3) for oil wells in reservoir A, sand group B, where the cumulative oil production increase slows down, the well opening times for oil wells where the formation pressure reaches 1.2 and 1.3 times the minimum miscibility pressure, the well opening times for oil wells where the stable production time increases slowly, the well opening times for oil wells where the formation pressure reaches 1.3 and 1.4 times the minimum miscibility pressure, and the well opening times for oil wells where the miscibility degree tends to stabilize, the well opening times for oil wells in reservoir A, sand group B, with the best displacement effect, are determined to be when the formation pressure reaches 1.3 times the minimum miscibility pressure. Combined with the fact that the minimum miscibility pressure in reservoir A, sand group B, is 24.5 MPa, the well opening time for oil wells in reservoir A, sand group B, with the best displacement effect, is determined to be when the formation pressure reaches 31.85 MPa.

Claims

1. A method for determining the open well time of a carbon dioxide miscible flooding well in a low permeability reservoir, characterized in that: Includes the following steps: 1) Calculate the cumulative oil production, stable production time, and degree of miscibility when the formation pressure reaches different multiples of the minimum miscibility pressure value during well opening using the carbon dioxide miscibility flooding numerical model of the target reservoir; the minimum multiple shall not be higher than 0.7 times, and the maximum multiple shall not be lower than 1.5 times. 2) Determine the well opening time by comprehensively considering the changes in cumulative oil production with well opening formation pressure, the changes in stable production time with well opening formation pressure, and the changes in miscibility with well opening formation pressure; The method for determining the well opening time includes the following steps: determining the well opening formation pressure when the increase in cumulative oil production slows down based on the change in cumulative oil production with the well opening formation pressure; determining the well opening formation pressure when the increase in stable production time slows down based on the change in stable production time with the well opening formation pressure; determining the well opening formation pressure when the miscibility tends to stabilize based on the change in miscibility with the well opening formation pressure; finding the intersection of the three well opening formation pressures to determine the well opening formation pressure, and then determining the well opening time.

2. The method for determining the well opening time of a carbon dioxide miscible flooding well in a low-permeability reservoir according to claim 1, characterized in that: The different multiples include 0.7 times, 0.8 times, 0.9 times, 1.0 times, 1.1 times, 1.2 times, 1.3 times, 1.4 times and 1.5 times.

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