A method for determining injection-production ratio in carbon dioxide displacement effective period

Abstract

The present application relates to the technical field of oil and gas field development, in particular to a kind of determination method for injection-production ratio in carbon dioxide displacement effective period, first consider the carbon dioxide channeling characteristics, accurately define the more accurate carbon dioxide displacement effective period starting moment by combining dynamic monitoring with prediction algorithm and based on the prediction deviation of carbon dioxide volume fraction, provide reliable time base for subsequent injection-production ratio calculation;Then based on Peng-Robinson state equation and multiphase fluid volume conversion method, systematically convert the ground injection and discharge into underground volume, so that the accuracy of the obtained carbon dioxide underground injection volume and total amount of backflow fluid underground is higher;Further, more accurate injection-production ratio is calculated by combining the relative size of carbon dioxide underground injection volume and total amount of backflow fluid underground.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas field development, and particularly relates to a method for determining injection-production ratio in a carbon dioxide displacement effective period. BACKGROUND

[0002] At present, many injection-production ratio calculation methods have been proposed in the development process of shale oil. In the prior art, the disclosure with the publication number CN106285585A discloses a method for calculating effective injection-production ratio of water drive reservoirs. The method calculates the injection-production ratio through water injection development. However, due to the development of nanometer pores in shale reservoirs, there are problems such as great injection difficulty and low sweep efficiency in the process of water injection development.

[0003] Carbon dioxide displacement has significant advantages compared to water displacement. Because of its low viscosity and easy miscibility with crude oil, it can effectively overcome the injection difficulty of nanoscale pores and greatly improve the micro-displacement efficiency. Therefore, CO2 displacement is considered as an effective technical direction for improving the recovery of shale oil. However, the current research and analysis methods of CO2 displacement injection-production ratio mostly directly follow the ideas and methods for conventional reservoirs, and cannot effectively deal with the two core challenges in the process of CO2 displacement of shale reservoirs: first, the strong heterogeneity of shale reservoirs leads to the problem that CO2 is easily "ineffective channeling" and "effective effect" is difficult to distinguish, which causes serious deviation in the judgment of the starting time of the displacement "effective period"; second, the injection and production fluids are not finely converted in the subsurface, and the high requirement of shale reservoirs for energy balance accuracy is ignored, which leads to the calculated injection-production ratio cannot truly reflect the balance relationship between underground energy supplement and deficit; therefore, the accuracy of the injection-production ratio calculated by the prior art for CO2 displacement of shale reservoirs is low. SUMMARY

[0004] In order to solve the technical problem of low accuracy of the injection-production ratio calculated by the prior art for CO2 displacement of shale reservoirs, the purpose of the present application is to provide a method for determining injection-production ratio in a carbon dioxide displacement effective period, and the technical solution adopted is as follows:

[0005] The first aspect of the present application provides a method for determining injection-production ratio in a carbon dioxide displacement effective period, comprising:

[0006] Collecting the carbon dioxide volume fraction of each production well at each sampling time; determining the starting time of the effective period according to the prediction deviation of the carbon dioxide volume fraction; collecting the ground carbon dioxide injection volume, ground standard temperature, ground standard pressure, reservoir in-situ temperature and reservoir in-situ pressure at each sampling time after the starting time of the effective period;

[0007] determining the carbon dioxide underground injection volume at each sampling time according to the relative size between the ground carbon dioxide injection volume, the ground standard temperature, the ground standard pressure, the reservoir in-situ temperature and the reservoir in-situ pressure;

[0008] determining the total amount of flowback fluid underground at each sampling time according to the relative size of the compression volume corresponding to the ground discharge water volume, the ground discharge crude oil volume and the ground discharge gas volume;

[0009] determining the injection-production ratio of each production well at the current time according to the relative size between the total amount of flowback fluid underground at the current time and the carbon dioxide underground injection volume at the current time.

[0010] Further, the obtaining process of the effective period starting time comprises:

[0011] sequentially taking each sampling time corresponding to a carbon dioxide volume fraction greater than a preset first volume fraction threshold as a target time;

[0012] obtaining the target time and the LOF value of each sampling time before the target time based on the LOF anomaly detection algorithm;

[0013] determining the volume fraction prediction value of the target time according to the carbon dioxide volume fraction of all sampling times before the target time in combination with the ARIMA prediction model, and determining the LOF prediction value of the target time according to the LOF value of all sampling times before the target time in combination with the ARIMA prediction model;

[0014] determining the corresponding volume fraction feature value according to the overall size of the LOF value, the LOF prediction value, the carbon dioxide volume fraction and the volume fraction prediction value of the target time;

[0015] screening out the effective period starting time according to the increasing trend of the volume fraction feature value of each sampling time in time sequence.

[0016] Further, the obtaining process of the volume fraction feature value comprises:

[0017] determining the corresponding real volume fraction contribution value according to the product between the negative correlation mapping value of the LOF value of the target time and the corresponding carbon dioxide volume fraction, determining the corresponding prediction volume fraction contribution value according to the product between the negative correlation mapping value of the LOF prediction value of the target time and the corresponding volume fraction prediction value, and determining the volume fraction feature value of the target time according to the sum value between the real volume fraction contribution value and the prediction volume fraction contribution value.

[0018] Further, the process of screening out the effective period starting time according to the increasing trend of the volume fraction feature value of each sampling time in time sequence comprises:

[0019] Each sampling moment and its corresponding next sampling moment are used as a sampling moment tuple; the sampling moment tuples in which the volume fraction feature values ​​of the two corresponding sampling moments are both greater than the preset second volume fraction threshold are used as decision tuples; the sampling moment corresponding to the first decision tuple in time sequence is used as the effective period start time.

[0020] Furthermore, the process of obtaining the underground carbon dioxide injection volume includes:

[0021] The ground standard temperature and the ground standard pressure are input into the Peng-Robinson equation of state, and the ground compressibility factor at each sampling time is output.

[0022] The reservoir in-situ temperature and reservoir in-situ pressure are input into the Peng-Robinson equation of state, and the reservoir compressibility factor at each sampling time is output.

[0023] Based on the overall relative magnitudes of the reservoir compressibility factor, the reservoir in-situ temperature, the surface standard pressure, the surface compressibility factor, the surface standard temperature, and the reservoir in-situ pressure, a comprehensive conversion factor is determined for each sampling time.

[0024] The underground carbon dioxide injection volume at each sampling time is determined by multiplying the comprehensive conversion factor with the surface carbon dioxide injection volume.

[0025] Furthermore, the process of obtaining the comprehensive conversion factor includes:

[0026] A first conversion factor is determined based on the product of the reservoir compressibility factor, the reservoir in-situ temperature, and the surface standard pressure; a second conversion factor is determined based on the product of the surface compressibility factor, the surface standard temperature, and the reservoir in-situ pressure; and a comprehensive conversion factor is determined for each sampling time based on the ratio between the first and second conversion factors.

[0027] Furthermore, the process of obtaining the total underground amount of the backflow fluid includes:

[0028] Obtain the reservoir condition oil density and the surface condition oil density; based on the relative magnitude between the reservoir condition oil density and the surface condition oil density, and combined with the surface discharged crude oil volume, determine the reservoir crude oil volume at each sampling time.

[0029] Obtain the dissolved gas-oil ratio; at each sampling time, determine the dissolved gas volume at ground level based on the product of the crude oil volume discharged from the ground and the dissolved gas-oil ratio; determine the free gas volume at ground level based on the difference between the gas volume discharged from the ground and the dissolved gas volume at ground level.

[0030] Based on the principle of the ideal gas law, combined with the surface free gas volume, surface standard pressure, reservoir in-situ pressure, reservoir in-situ temperature and surface standard temperature, the reservoir free gas volume at each sampling time is determined.

[0031] Obtain the reservoir water density and the surface water density; determine the water volume conversion factor based on the ratio between the surface water density and the reservoir water density; determine the reservoir water volume based on the product of the surface water discharge volume and the water volume conversion factor.

[0032] The total underground flow of fluid at each sampling time is determined based on the sum of the reservoir crude oil volume, reservoir free gas volume, and reservoir water volume.

[0033] Furthermore, the process of obtaining the volume of crude oil in the reservoir includes:

[0034] The crude oil volume factor is determined based on the ratio between the reservoir oil density and the surface oil density; the reservoir crude oil volume at each sampling time is determined based on the product of the surface-discharged crude oil volume and the crude oil volume factor.

[0035] Furthermore, the process of obtaining the reservoir free gas volume includes:

[0036] The first gas state value is determined by multiplying the surface standard pressure and the reservoir in-situ temperature; the second gas state value is determined by multiplying the reservoir in-situ pressure and the surface standard temperature; the ideal gas state parameter is determined by the ratio between the first gas state value and the second gas state value; and the reservoir free gas volume at each sampling time is determined by multiplying the surface free gas volume and the ideal gas state parameter.

[0037] Furthermore, the process of obtaining the injection-production ratio includes:

[0038] The injection-production ratio of each production well at the current moment is determined by the ratio between the total underground flow of backflow fluid and the underground injection volume of carbon dioxide at the current moment.

[0039] Secondly, this application provides a system for determining the injection-production ratio during the effective period of carbon dioxide displacement, the system comprising:

[0040] The data acquisition and preprocessing module is used to collect the carbon dioxide volume fraction of each production well at each sampling time; determine the start time of the effective period based on the prediction deviation of the carbon dioxide volume fraction; after the start time of the effective period, collect the surface carbon dioxide injection volume, surface standard temperature, surface standard pressure, reservoir in-situ temperature and reservoir in-situ pressure at each sampling time.

[0041] The first determining module is used to determine the underground carbon dioxide injection volume at each sampling time based on the relative magnitudes between the ground carbon dioxide injection volume, ground standard temperature, ground standard pressure, reservoir in-situ temperature, and reservoir in-situ pressure.

[0042] The second determining module is used to determine the total underground amount of backflow fluid at each sampling time based on the relative size of the compressed volumes corresponding to the surface discharge water volume, surface discharge crude oil volume, and surface discharge gas volume at each sampling time.

[0043] The injection-production ratio determination module is used to determine the injection-production ratio of each production well at the current moment based on the relative size between the total underground flow of backflow fluid and the underground injection volume of carbon dioxide at the current moment.

[0044] Thirdly, this application provides a computer device including a memory and a processor. The memory is used to store computer program code, and the processor is used to call and run the computer program code from the memory to perform the method as described in the first aspect of this application or any embodiment of the first aspect.

[0045] Fourthly, this application provides a computer program product comprising computer program code, which, when executed, performs the method as described in the first aspect of this application or any embodiment thereof.

[0046] Fifthly, this application provides a computer-readable storage medium that stores computer program code, which, when executed, performs the method as described in the first aspect of this application or any embodiment thereof.

[0047] This application has the following beneficial effects:

[0048] This application first considers the characteristics of carbon dioxide migration and combines dynamic monitoring and prediction algorithms with prediction deviations based on carbon dioxide volume fraction to accurately define the effective start time of carbon dioxide displacement, providing a reliable time benchmark for subsequent injection-production ratio calculation. Then, based on the Peng-Robinson equation of state and multiphase fluid volume conversion method, the surface injection and discharge volumes are systematically converted into underground volumes, making the obtained underground carbon dioxide injection volume and underground total amount of return fluid more accurate. Furthermore, the relative sizes of the underground carbon dioxide injection volume and the underground total amount of return fluid are combined to calculate the injection-production ratio more accurately. Attached Figure Description

[0049] To more clearly illustrate the technical solutions and advantages in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0050] Figure 1 The flowchart illustrates a method for determining the injection-production ratio during the effective period of carbon dioxide displacement, as provided in one embodiment of the present invention.

[0051] Figure 2 This is a schematic representation of cumulative water production data for the JHL well group in the Songliao Basin, provided as an embodiment of the present invention.

[0052] Figure 3 This is a schematic representation of cumulative oil production data for the JHL well group in the Songliao Basin, provided as an embodiment of the present invention.

[0053] Figure 4 This is a schematic representation of cumulative gas production data for the JHL well group in the Songliao Basin, provided as an embodiment of the present invention.

[0054] Figure 5 This is a schematic representation of real-time injection-production ratio data for the JHL well group in the Songliao Basin, provided as an embodiment of the present invention.

[0055] Figure 6 This is a structural diagram of a system for determining the injection-production ratio during the effective period of carbon dioxide displacement, provided in one embodiment of the present invention. Detailed Implementation

[0056] To further illustrate the technical means and effects adopted by the present invention to achieve its intended purpose, the following, in conjunction with the accompanying drawings and preferred embodiments, details the specific implementation, structure, features, and effects of a method for determining the injection-production ratio during carbon dioxide displacement effectiveness according to the present invention. In the following description, different "one embodiment" or "another embodiment" do not necessarily refer to the same embodiment, and specific features, structures, or characteristics in one or more embodiments can be combined in any suitable form. Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as implying or suggesting relative importance or implicitly indicating the number of indicated technical features. Thus, a feature defined with "first" or "second" may explicitly or implicitly include one or more of that feature.

[0057] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0058] The following describes in detail, with reference to the accompanying drawings, a specific scheme for determining the injection-production ratio during the effective period of carbon dioxide displacement provided by the present invention.

[0059] This application provides a method for determining the injection-production ratio during the effective period of carbon dioxide displacement. Please refer to [link to relevant documentation]. Figure 1 The diagram illustrates a flowchart of a method for determining the injection-production ratio during the effective period of carbon dioxide displacement, according to an embodiment of the present invention. The method includes:

[0060] Step S101: Collect the carbon dioxide volume fraction of each production well at each sampling time; determine the start time of the effective period based on the predicted deviation of the carbon dioxide volume fraction; after the start time of the effective period, collect the surface carbon dioxide injection volume, surface standard temperature, surface standard pressure, reservoir in-situ temperature and reservoir in-situ pressure at each sampling time.

[0061] A carbon dioxide volume fraction monitoring device is installed at the wellhead of each production well to monitor the carbon dioxide volume fraction at each sampling time. During the calculation and analysis of the injection-production ratio (IPR) for the effective period of carbon dioxide displacement, deviations in the start time of the effective period can cause mismatches in the injection and production data, affecting the accuracy of the IPR results. Specifically, an early start time can lead to the actual time interval before the effective period is reached being judged as the effective period, resulting in a large deviation in the IPR calculation and failing to reflect the true carbon dioxide displacement injection-production balance. Conversely, a late start time can lead to a large difference in the actual injection-production balance, resulting in a large error in the analysis and judgment of injection efficiency. Therefore, based on the above analysis, to accurately calculate the IPR, this application combines dynamic monitoring with a prediction algorithm to determine a more accurate start time of the effective period based on the prediction deviation of the carbon dioxide volume fraction. It should be noted that the subsequent analysis process is performed on the same production well, and will not be further elaborated upon.

[0062] Preferably, in some possible implementations of the embodiments of the present invention, the process of obtaining the start time of the validity period includes:

[0063] Each sampling time where the corresponding carbon dioxide volume fraction is greater than a preset first volume fraction threshold is sequentially taken as the target time. In a specific implementation of this invention, the initial sampling frequency is set to once every 2 hours. After the first sampling time where the carbon dioxide volume fraction is greater than the preset first volume fraction threshold occurs, the subsequent sampling frequency is set to once every 30 minutes. The preset first volume fraction threshold is set to 5%, which is an empirical value. A carbon dioxide volume fraction greater than 5% indicates that the injected carbon dioxide may gradually stabilize and reach the production well, so a target time needs to be introduced for more accurate analysis. Furthermore, based on the carbon dioxide volume fraction of all sampling times before the target time and combined with the ARIMA prediction model, the predicted volume fraction value of the target time is determined. Here, by introducing the predicted volume fraction value, a rational expectation is provided for the temporal change of carbon dioxide volume fraction, so that when the carbon dioxide volume fraction at the target time is affected by carbon dioxide crosstalk, it can provide compensation for the final volume analysis characteristic value and reduce the impact of carbon dioxide crosstalk.

[0064] Furthermore, the LOF value at the target time and at each sampling time before the target time is obtained based on the LOF anomaly detection algorithm. The predicted LOF value at the target time is determined by combining the LOF values ​​of all sampling times before the target time with the ARIMA prediction model. According to the characteristics of the LOF anomaly detection algorithm, a larger LOF value indicates a more abnormal time-series change in carbon dioxide volume fraction, more consistent with the situation where abnormal fluctuations in carbon dioxide volume fraction are caused by carbon dioxide cross-flow. The LOF value can evaluate the reliability of carbon dioxide volume fraction. A larger LOF value indicates a more severe degree of abnormal fluctuations in carbon dioxide volume fraction caused by carbon dioxide cross-flow, resulting in lower reliability of the corresponding carbon dioxide volume fraction and requiring greater weight for compensation through the volume fraction prediction value. Furthermore, if the predicted LOF value based on the time-series change of the LOF value is large, it means that even without considering the current monitoring value, based solely on historical trends, the system is expected to enter an abnormal state. In this case, the reliability of the predicted volume fraction value will decrease, requiring a smaller weight to be introduced when compensating for the carbon dioxide volume fraction. It should be noted that the LOF anomaly detection algorithm is a well-known technique in the field of science and will not be elaborated further here.

[0065] Therefore, based on the above characteristics, this embodiment of the invention determines the corresponding volume fraction feature value according to the overall magnitude of the LOF value, LOF predicted value, carbon dioxide volume fraction, and volume fraction predicted value at the target time. The process of obtaining the volume fraction feature value includes: determining the corresponding true volume fraction contribution value based on the product between the negative correlation mapping value of the LOF value at the target time and the corresponding carbon dioxide volume fraction; determining the corresponding predicted volume fraction contribution value based on the product between the negative correlation mapping value of the LOF predicted value at the target time and the corresponding volume fraction predicted value; and determining the volume fraction feature value at the target time based on the sum of the true volume fraction contribution value and the predicted volume fraction contribution value.

[0066] Since the higher the LOF value at the target time, the lower the reliability of the corresponding carbon dioxide volume fraction, and the higher the LOF prediction value at the target time, the lower the reliability of the corresponding predicted volume fraction contribution value, the embodiments of the present invention perform negative correlation processing on the LOF value and the LOF prediction value respectively and then perform weighting, so that the accuracy of the obtained volume fraction feature value is higher.

[0067] In one specific implementation of this invention, the process of obtaining the volume fraction characteristic value is expressed by the following formula: ;in, For the target time The volume fraction characteristic value; For the target time LOF value; For the target time LOF predicted value; For the target time The volume fraction of carbon dioxide; For the target time The predicted volume fraction value; For the target time The true volume fraction contribution value; For the target time The predicted volume fraction contribution value; through the negative correlation mapping method in the formula, the sum between the weight of carbon dioxide volume fraction and the weight of the predicted volume fraction value can be made to 1, thereby improving the robustness of the volume fraction feature value obtained after weighted summation.

[0068] Compared to directly determining the start time of the effective period based on the volume fraction of carbon dioxide, determining the start time based on the volume fraction characteristic value takes into account the characteristics of carbon dioxide migration, making the obtained start time of the effective period more accurate. This embodiment of the invention further filters the start time of the effective period based on the increasing trend of the volume fraction characteristic values ​​of each sampling time in chronological order. Specifically: each sampling time and its corresponding next sampling time are used as a sampling time binary; the sampling time binary where the volume fraction characteristic values ​​of two corresponding sampling times are both greater than a preset second volume fraction threshold is used as a judgment binary; the sampling time corresponding to the first judgment binary in chronological order is taken as the start time of the effective period. That is, when the volume fraction characteristic values ​​of two consecutive sampling times are both greater than the preset second volume fraction threshold for the first time, it indicates that carbon dioxide has reached the production well in a stable overall trend. Compared to directly analyzing the volume fraction characteristic value of a single sampling time combined with the preset second volume fraction threshold, this reduces the impact of errors and improves the accuracy of the obtained start time of the effective period. In one specific implementation of this invention, the preset second volume fraction threshold is set to 10%, which can be adjusted according to the specific implementation environment, and will not be elaborated further here.

[0069] In one specific implementation of this invention, at each sampling moment, the surface temperature of the production well surface collected by a temperature sensor is used as the corresponding standard surface temperature, and the standard atmospheric pressure is used as the standard surface pressure. The in-situ reservoir temperature of the shale oil well production layer is collected by a production logging combination instrument, and the in-situ reservoir pressure of the shale oil well production layer is collected by a production logging pressure tool. Then, the crude oil density of the crude oil discharged from the surface is measured in the laboratory to determine the surface condition oil density. Then, the crude oil density of the crude oil discharged from the surface is measured in the laboratory under the in-situ reservoir pressure and temperature to determine the corresponding reservoir condition oil density. Similarly, the surface water density and reservoir water density are measured in the laboratory.

[0070] Furthermore, the underground carbon dioxide injection volume, surface water discharge volume, surface crude oil discharge volume, and surface gas discharge volume are read at each sampling time through the ground metering system. It should be noted that the underground carbon dioxide injection volume, surface water discharge volume, surface crude oil discharge volume, and surface gas discharge volume are all cumulative values ​​that are measured starting from the start time of the effective period. The sampling frequency after the start time of the effective period is set to be once every 24 hours, which can be adjusted according to the specific implementation environment.

[0071] In this embodiment of the invention, taking the JHL well group in the Songliao Basin as an example, the dynamic production data table of the oil well is compiled based on the data collected at each sampling time, and the data tables corresponding to the cumulative water production, cumulative oil production, and cumulative gas production are determined respectively. Please refer to...Figure 2 This illustrates a schematic representation of cumulative water production data for the JHL well group in the Songliao Basin, provided by an embodiment of the present invention; please refer to [link / reference]. Figure 3 This illustrates a schematic representation of cumulative oil production data for the JHL well group in the Songliao Basin, provided by an embodiment of the present invention; please refer to [link / reference]. Figure 4 This illustrates a schematic representation of cumulative gas production data for the JHL well group in the Songliao Basin, according to an embodiment of the present invention; wherein, Figure 2 , Figure 3 and Figure 4 JHL-11, JHL-12, JHL-13, JHL-14, HL-21, HL-22, HL-23, HL-24, HL-31, HL-32, HL-33, and HL-34 are the production well codes in the JHL well group of the Songliao Basin. Figure 2 The cumulative water production in this figure refers to the volume of surface water discharged as analyzed in the embodiments of the present invention. Figure 3 The cumulative oil production is the volume of crude oil discharged from the surface analyzed in this embodiment of the invention. Figure 4 The cumulative gas production is the volume of gas discharged from the surface analyzed in this embodiment of the invention. It should be noted that this embodiment of the invention only analyzes the data of one production well, such as JHL-11. The analysis method for other production wells is the same, and will not be described further here.

[0072] Step S102: Determine the underground carbon dioxide injection volume at each sampling time based on the relative magnitudes of the ground carbon dioxide injection volume, ground standard temperature, ground standard pressure, reservoir in-situ temperature, and reservoir in-situ pressure.

[0073] More accurate injection-production ratio calculations require calculations based on the underground volume of carbon dioxide and the underground volumes of water, crude oil, and gas discharged from the surface. However, surface carbon dioxide is compressed under reservoir pressure and temperature; therefore, the underground carbon dioxide injection volume needs to be calculated based on the surface carbon dioxide injection volume. This calculation ratio requires analysis of the relative magnitudes of surface standard temperature, surface standard pressure, reservoir in-situ temperature, and reservoir in-situ pressure. Therefore, this embodiment of the invention determines the underground carbon dioxide injection volume at each sampling time based on the relative magnitudes of the surface carbon dioxide injection volume, surface standard temperature, surface standard pressure, reservoir in-situ temperature, and reservoir in-situ pressure.

[0074] Preferably, in some possible implementations of the embodiments of the present invention, the process of obtaining the underground carbon dioxide injection volume includes:

[0075] The surface standard temperature and surface standard pressure are input into the Peng-Robinson equation of state, and the surface compressibility factor at each sampling time is output. The reservoir in-situ temperature and reservoir in-situ pressure are input into the Peng-Robinson equation of state, and the reservoir compressibility factor at each sampling time is output. Based on the overall relative magnitudes of the reservoir compressibility factor, reservoir in-situ temperature, surface standard pressure, surface compressibility factor, and surface standard temperature and reservoir in-situ pressure, the comprehensive conversion factor at each sampling time is determined.

[0076] Preferably, in some possible implementations of the embodiments of the present invention, the process of obtaining the comprehensive conversion factor includes:

[0077] The first conversion factor is determined by multiplying the reservoir compressibility factor, the reservoir in-situ temperature, and the surface standard pressure; the second conversion factor is determined by multiplying the surface compressibility factor, the surface standard temperature, and the reservoir in-situ pressure; and the comprehensive conversion factor for each sampling time is determined by the ratio between the first and second conversion factors.

[0078] Since the number of carbon dioxide moles remains constant both on the surface and underground, the conversion ratio between the surface carbon dioxide injection volume and the underground carbon dioxide injection volume can be calculated based on this constant mole number and the environmental differences between the surface and reservoir. Firstly, based on the principle of the real gas law, the number of carbon dioxide moles can be determined using the surface standard pressure, surface compressibility factor, surface standard temperature, and surface carbon dioxide injection volume combined with a universal gas constant. Specifically, the number of carbon dioxide moles at the corresponding sampling time can be determined by using the surface standard pressure and surface carbon dioxide injection volume as the numerator, and the surface compressibility factor, universal gas constant, and surface standard temperature as the denominator. Then, based on the property that the number of carbon dioxide moles remains constant and the real gas equation of state, the underground carbon dioxide injection volume can be indirectly determined by considering the reservoir compressibility factor, in-situ reservoir temperature, and in-situ reservoir pressure in the underground environment. Specifically, the underground carbon dioxide injection volume can be determined by multiplying the number of carbon dioxide moles, the universal gas constant, the in-situ reservoir temperature, and the reservoir compressibility factor as the numerator, and using the in-situ reservoir pressure as the numerator. The ratio between the underground carbon dioxide injection volume and the surface carbon dioxide injection volume is the corresponding comprehensive conversion factor.

[0079] Furthermore, the underground carbon dioxide injection volume at each sampling time can be determined by multiplying the comprehensive conversion factor by the surface carbon dioxide injection volume. In a specific implementation of this invention, the process of obtaining the underground carbon dioxide injection volume includes: ;in, Sampling time The volume of carbon dioxide injected underground; Sampling time The volume of carbon dioxide injected onto the ground; Sampling time The comprehensive conversion factor is as follows; Sampling time reservoir compressibility factor; Sampling time The ground compressibility factor; Sampling time The standard ground pressure; Sampling time In-situ reservoir pressure; Sampling time The in-situ temperature of the reservoir; Sampling time The surface standard temperature; it should be noted that the reservoir compressibility factor, surface compressibility factor, surface standard pressure, reservoir in-situ pressure, surface standard temperature and reservoir in-situ temperature usually do not change. These parameters collected in the initial state can be directly used as the parameters at each sampling time, and will not be elaborated further here.

[0080] Step S103: Determine the total underground amount of backflow fluid at each sampling time based on the relative sizes of the compressed volumes corresponding to the surface water volume, surface crude oil volume, and surface gas volume at each sampling time.

[0081] After calculating the underground carbon dioxide injection volume, it is then necessary to determine the underground volume parameters of the surface-discharged water, crude oil, and gas based on the surface-discharged water volume, crude oil volume, and gas volume, as well as the reservoir environment. Therefore, in this embodiment of the invention, the total underground backflow fluid volume at each sampling time is determined based on the relative size of the compressed volume corresponding to the surface-discharged water volume, crude oil volume, and gas volume at each sampling time.

[0082] Preferably, in some possible implementations of the embodiments of the present invention, the process of obtaining the total amount of underground backflow fluid includes:

[0083] The process involves obtaining the reservoir-condition oil density and the surface-condition oil density; determining the reservoir crude oil volume at each sampling time based on the relative magnitude between the reservoir-condition oil density and the surface-condition oil density, combined with the surface-discharged crude oil volume; the process of obtaining the reservoir crude oil volume includes: determining the crude oil volume coefficient based on the ratio between the reservoir-condition oil density and the surface-condition oil density; and determining the reservoir crude oil volume at each sampling time based on the product of the surface-discharged crude oil volume and the crude oil volume coefficient.

[0084] Since the mass of crude oil in the reservoir is the same as that on the surface, the ratio between the oil density under reservoir conditions and the oil density under surface conditions should be the same as the ratio between the volume of crude oil discharged from the surface and the crude oil volume factor. Therefore, after determining the crude oil volume factor, the corresponding crude oil volume in the reservoir can be determined by multiplying the volume of crude oil discharged from the surface and the crude oil volume factor.

[0085] To obtain the dissolved gas-oil ratio, this embodiment of the invention first collects crude oil samples using a high-pressure sampler. Then, based on the ratio between the volume of all separated gases and the volume of degassed crude oil after gas separation under standard experimental conditions, the dissolved gas-oil ratio is determined. Further, at each sampling time, the surface dissolved gas volume is determined by multiplying the surface discharged crude oil volume by the dissolved gas-oil ratio; the surface free gas volume is determined by the difference between the surface discharged gas volume and the surface dissolved gas volume. The surface dissolved gas volume is the volume of gas separated from the crude oil. When calculating the free gas volume in the reservoir, this gas volume will affect the calculation results. Therefore, it is necessary to first subtract this surface dissolved gas volume from the surface discharged gas volume to improve the accuracy of the reservoir free gas volume calculated subsequently based on the surface free gas volume.

[0086] Based on the ideal gas law principle, combined with the surface free gas volume, surface standard pressure, reservoir in-situ pressure, reservoir in-situ temperature, and surface standard temperature, the reservoir free gas volume at each sampling time is determined. Similar to the calculation principle of underground carbon dioxide injection volume, the number of free gas particles in the reservoir and on the surface is the same. Therefore, the ratio obtained by multiplying the surface free gas volume by the surface standard pressure as the numerator and the surface standard temperature as the denominator is a constant. Similarly, the ratio obtained by multiplying the reservoir free gas volume by the reservoir in-situ pressure as the numerator and the reservoir in-situ temperature as the denominator should also be the same constant. Therefore, based on the corresponding changing relationships, the corresponding reservoir free gas volume can be determined based on the surface free gas volume, surface standard pressure, reservoir in-situ pressure, reservoir in-situ temperature, and surface standard temperature.

[0087] Based on the ideal gas law, the process of obtaining the reservoir free gas volume includes: determining the first gas state value based on the product of the surface standard pressure and the reservoir in-situ temperature; determining the second gas state value based on the product of the reservoir in-situ pressure and the surface standard temperature; determining the ideal gas state parameters based on the ratio between the first and second gas state values; and determining the reservoir free gas volume at each sampling time based on the product of the surface free gas volume and the ideal gas state parameters.

[0088] In one specific implementation of this invention, the process of obtaining the reservoir free gas volume includes: ;in, Sampling time The volume of free gas in the reservoir; Sampling time The volume of free gas at the ground; Sampling time The standard ground pressure; Sampling time In-situ reservoir pressure; Sampling time The in-situ temperature of the reservoir; Sampling time The standard ground temperature; Sampling time The first gas state value; Sampling time The second gas state value; Sampling time Ideal gas state parameters.

[0089] Obtain the reservoir water density and the surface water density; determine the water volume conversion factor based on the ratio between the surface water density and the reservoir water density; determine the reservoir water volume by multiplying the surface-discharged water volume by the water volume conversion factor. Since the mass of the discharged water in the reservoir is the same as its mass on the surface, the ratio between the reservoir condition oil density and the surface condition oil density should be the same as the ratio between the surface-discharged crude oil volume and the crude oil volume factor; therefore, after determining the crude oil volume factor, the corresponding reservoir crude oil volume can be determined by multiplying the surface-discharged crude oil volume by the crude oil volume factor.

[0090] Finally, by combining the volumes of crude oil, water, and free gas in the reservoir, and based on the sum of the volumes of crude oil, free gas, and water in the reservoir, the total amount of backflow fluid underground at each sampling time is determined.

[0091] In one specific implementation of this invention, the process of obtaining the total underground amount of backflow fluid includes: ;in, Sampling time The total amount of underground fluid discharged; Sampling time The volume of crude oil in the reservoir; Sampling time The volume of free gas in the reservoir; Sampling time The volume of reservoir water.

[0092] Step S104: Determine the injection-production ratio of each production well at the current moment based on the relative size between the total underground flow of backflow fluid and the underground carbon dioxide injection volume at the current moment.

[0093] Finally, based on the calculation principle of the injection-production ratio, the injection-production ratio is determined based on the determined total underground flowback fluid volume and the underground carbon dioxide injection volume. Preferably, in some possible implementations of this invention, the process of obtaining the injection-production ratio includes: determining a more accurate injection-production ratio for each production well at the current moment by using the ratio between the current underground flowback fluid volume and the current underground carbon dioxide injection volume. Please refer to [link to relevant documentation]. Figure 5 This illustrates a schematic representation of real-time injection-production ratio data for the JHL well group in the Songliao Basin, provided by an embodiment of the present invention. Figure 5 The injection-production ratio calculated in real time is statistically analyzed to provide solid data support and decision-making basis for the formulation, optimization and on-site production guidance of carbon dioxide huff and puff programs.

[0094] In summary, a method for determining the injection-production ratio during the effective period of carbon dioxide displacement first considers the characteristics of carbon dioxide migration. By combining dynamic monitoring and prediction algorithms with prediction deviations based on carbon dioxide volume fraction, a more accurate starting time for the effective period of carbon dioxide displacement is defined, providing a reliable time reference for subsequent injection-production ratio calculations. Then, based on the Peng-Robinson equation of state and multiphase fluid volume conversion methods, the surface injection and discharge volumes are systematically converted into underground volumes, resulting in higher accuracy of the obtained underground carbon dioxide injection volume and the total underground amount of return fluid. Furthermore, the relative sizes of the underground carbon dioxide injection volume and the total underground amount of return fluid are combined to calculate the injection-production ratio more accurately.

[0095] This application also provides a system for determining the injection-production ratio during the effective period of carbon dioxide displacement; please refer to [link to relevant documentation]. Figure 6 The diagram illustrates a structural diagram of a system for determining the injection-production ratio during the effective period of carbon dioxide displacement, provided by an embodiment of the present invention. The system includes: a data acquisition and preprocessing module 601, a first determination module 602, a second determination module 603, and an injection-production ratio determination module 604.

[0096] The data acquisition and preprocessing module 601 is used to acquire the carbon dioxide volume fraction of each production well at each sampling time; determine the start time of the effective period based on the prediction deviation of the carbon dioxide volume fraction; and after the start time of the effective period, acquire the surface carbon dioxide injection volume, surface standard temperature, surface standard pressure, reservoir in-situ temperature and reservoir in-situ pressure at each sampling time.

[0097] The first determining module 602 is used to determine the underground carbon dioxide injection volume at each sampling time based on the relative magnitudes between the ground carbon dioxide injection volume, ground standard temperature, ground standard pressure, reservoir in-situ temperature, and reservoir in-situ pressure.

[0098] The second determining module 603 is used to determine the total underground amount of backflow fluid at each sampling time based on the relative size of the compressed volumes corresponding to the surface water volume, surface crude oil volume, and surface gas volume at each sampling time.

[0099] The injection-production ratio determination module 604 is used to determine the injection-production ratio of each production well at the current moment based on the relative size between the total underground flow of backflow fluid at the current moment and the underground injection volume of carbon dioxide at the current moment.

[0100] It should be noted that the system provided in the above embodiments is only an example of the division of the above functional modules. In practical applications, the above functions can be assigned to different functional modules as needed, that is, the internal structure of the computer device can be divided into different functional modules to complete all or part of the functions described above. In addition, the system for determining the injection-production ratio during the effective period of carbon dioxide displacement provided in the above embodiments and the method for determining the injection-production ratio during the effective period of carbon dioxide displacement are based on the same concept. The specific implementation process is detailed in the method embodiment and will not be repeated here.

[0101] This application also provides a computer device, which includes a memory, a processor, and a computer program stored in the memory and running on the processor. When the processor executes the computer program, the computer device can execute any of the methods described above for determining the injection-production ratio during the effective period of carbon dioxide displacement.

[0102] This application also provides a computer program product that, when run on a computer device, enables the computer device to execute any of the aforementioned methods for determining the injection-production ratio during the effective period of carbon dioxide displacement.

[0103] This application also provides a computer-readable storage medium storing computer program code. When the computer program code is run on a computer device, the computer device can execute any of the aforementioned methods for determining the injection-production ratio during the effective period of carbon dioxide displacement.

[0104] In the embodiments provided in this application, it should be understood that the computer device, computer program product and computer-readable storage medium provided are all used to perform the corresponding methods provided above, and therefore the beneficial effects they can achieve can be referred to the beneficial effects of the methods provided above, which will not be repeated here.

[0105] It should be noted that the order of the above embodiments of the present invention is merely for descriptive purposes and does not represent the superiority or inferiority of the embodiments. The processes depicted in the accompanying drawings do not necessarily require a specific or sequential order to achieve the desired result. In some embodiments, multitasking and parallel processing are also possible or may be advantageous.

[0106] The various embodiments in this specification are described in a progressive manner. The same or similar parts between the various embodiments can be referred to each other. Each embodiment focuses on describing the differences from other embodiments.

Claims

1. A method for determining the injection-production ratio during the effective period of carbon dioxide displacement, characterized in that, The method includes: Collect the carbon dioxide volume fraction of each production well at each sampling time; determine the start time of the effective period based on the predicted deviation of the carbon dioxide volume fraction; after the start time of the effective period, collect the surface carbon dioxide injection volume, surface standard temperature, surface standard pressure, reservoir in-situ temperature and reservoir in-situ pressure at each sampling time. The underground carbon dioxide injection volume at each sampling time is determined based on the relative magnitudes of the ground carbon dioxide injection volume, ground standard temperature, ground standard pressure, reservoir in-situ temperature, and reservoir in-situ pressure. The total underground amount of backflow fluid at each sampling time is determined based on the relative sizes of the compressed volumes corresponding to the surface water volume, surface crude oil volume, and surface gas volume at each sampling time. The injection-production ratio of each production well at the current moment is determined based on the relative size between the total underground flow of backflow fluid and the underground injection volume of carbon dioxide at the current moment.

2. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 1, characterized in that, The process of obtaining the start time of the validity period includes: Each sampling time in which the corresponding carbon dioxide volume fraction is greater than the preset first volume fraction threshold is taken as the target time. The LOF value at the target time and at each sampling time before the target time is obtained based on the LOF anomaly detection algorithm; Based on the carbon dioxide volume fraction of all sampling times before the target time and combined with the ARIMA prediction model, the predicted volume fraction value of the target time is determined; based on the LOF value of all sampling times before the target time and combined with the ARIMA prediction model, the predicted LOF value of the target time is determined. Based on the LOF value at the target time, the predicted LOF value, the carbon dioxide volume fraction, and the overall magnitude of the predicted volume fraction value, the corresponding volume fraction characteristic value is determined. Based on the increasing trend of the volume fraction characteristic values ​​at each sampling time in chronological order, the start time of the effective period is selected.

3. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 2, characterized in that, The process of obtaining the volume fraction feature value includes: The true volume fraction contribution value is determined by multiplying the negative correlation mapping value of the LOF value at the target time with the corresponding carbon dioxide volume fraction; the predicted volume fraction contribution value is determined by multiplying the negative correlation mapping value of the predicted LOF value at the target time with the corresponding volume fraction prediction value; and the volume fraction characteristic value at the target time is determined by the sum of the true volume fraction contribution value and the predicted volume fraction contribution value.

4. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 2, characterized in that, The process of selecting the start time of the effective period based on the increasing trend of the volume fraction characteristic values ​​at each sampling time in chronological order includes: Each sampling moment and its corresponding next sampling moment are used as a sampling moment tuple; the sampling moment tuples in which the volume fraction feature values ​​of the two corresponding sampling moments are both greater than the preset second volume fraction threshold are used as decision tuples; the sampling moment corresponding to the first decision tuple in time sequence is used as the effective period start time.

5. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 1, characterized in that, The process of obtaining the underground carbon dioxide injection volume includes: The ground standard temperature and the ground standard pressure are input into the Peng-Robinson equation of state, and the ground compressibility factor at each sampling time is output. The reservoir in-situ temperature and reservoir in-situ pressure are input into the Peng-Robinson equation of state, and the reservoir compressibility factor at each sampling time is output. Based on the overall relative magnitudes of the reservoir compressibility factor, the reservoir in-situ temperature, the surface standard pressure, the surface compressibility factor, the surface standard temperature, and the reservoir in-situ pressure, a comprehensive conversion factor is determined for each sampling time. The underground carbon dioxide injection volume at each sampling time is determined by multiplying the comprehensive conversion factor with the surface carbon dioxide injection volume.

6. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 5, characterized in that, The process of obtaining the comprehensive conversion factor includes: A first conversion factor is determined based on the product of the reservoir compressibility factor, the reservoir in-situ temperature, and the surface standard pressure; a second conversion factor is determined based on the product of the surface compressibility factor, the surface standard temperature, and the reservoir in-situ pressure; and a comprehensive conversion factor is determined for each sampling time based on the ratio between the first and second conversion factors.

7. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 1, characterized in that, The process of obtaining the total amount of underground backflow fluid includes: Obtain the reservoir condition oil density and the surface condition oil density; based on the relative magnitude between the reservoir condition oil density and the surface condition oil density, and combined with the surface discharged crude oil volume, determine the reservoir crude oil volume at each sampling time. Obtain the dissolved gas-oil ratio; at each sampling time, determine the dissolved gas volume at ground level based on the product of the crude oil volume discharged from the ground and the dissolved gas-oil ratio; determine the free gas volume at ground level based on the difference between the gas volume discharged from the ground and the dissolved gas volume at ground level. Based on the principle of the ideal gas law, combined with the surface free gas volume, surface standard pressure, reservoir in-situ pressure, reservoir in-situ temperature and surface standard temperature, the reservoir free gas volume at each sampling time is determined. Obtain the reservoir water density and the surface water density; determine the water volume conversion factor based on the ratio between the surface water density and the reservoir water density; determine the reservoir water volume based on the product of the surface water discharge volume and the water volume conversion factor. The total underground flow of fluid at each sampling time is determined based on the sum of the reservoir crude oil volume, reservoir free gas volume, and reservoir water volume.

8. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 7, characterized in that, The process of obtaining the volume of crude oil in the reservoir includes: The crude oil volume factor is determined based on the ratio between the reservoir oil density and the surface oil density; the reservoir crude oil volume at each sampling time is determined based on the product of the surface-discharged crude oil volume and the crude oil volume factor.

9. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 7, characterized in that, The process of obtaining the volume of free gas in the reservoir includes: The first gas state value is determined by multiplying the surface standard pressure and the reservoir in-situ temperature; the second gas state value is determined by multiplying the reservoir in-situ pressure and the surface standard temperature; the ideal gas state parameter is determined by the ratio between the first gas state value and the second gas state value; and the reservoir free gas volume at each sampling time is determined by multiplying the surface free gas volume and the ideal gas state parameter.

10. The method for determining the injection-production ratio during the effective period of carbon dioxide displacement according to claim 1, characterized in that, The process of obtaining the injection-production ratio includes: The injection-production ratio of each production well at the current moment is determined by the ratio between the total underground flow of backflow fluid and the underground injection volume of carbon dioxide at the current moment.

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