A method for determining a critical heat injection temperature for hot water flooding of a heavy oil reservoir

Abstract

The present application relates to the field of oil reservoir development, and discloses a method for determining the critical injection temperature of hot water flooding in a heavy oil reservoir, comprising the following steps: S1, determining the starting pressure gradient of a simulated heavy oil reservoir hot water flooding experiment at different temperatures and different permeabilities, and fitting a starting pressure gradient-temperature curve with temperature as the horizontal coordinate and starting pressure gradient as the vertical coordinate under the same permeability; S2, determining the critical injection temperature of the reservoir hot water flooding experiment according to the starting pressure gradient-temperature curve. The method has the advantages of quantifiability and strong operability, is suitable for determining the injection and production parameters of a heavy oil reservoir with thermal recovery, and has important significance for the design of a heavy oil reservoir thermal recovery scheme.

Description

Technical Field

[0001] This invention relates to the field of reservoir development, and more specifically to a method for determining the critical injection temperature for hot water flooding in heavy oil reservoirs. Background Technology

[0002] Heating heavy oil can significantly reduce its viscosity, thereby increasing its permeability in porous media. Heavy oil thermal recovery technologies (such as steam injection, steam drive, and steam-assisted gravity drainage) can substantially improve the recovery rate of heavy oil fields. Years of development practice in the Bohai Oilfield have shown that heavy oil reservoirs with formation viscosity below 350 mPa•s can achieve good economic benefits through horizontal wells and chemical flooding. However, for special heavy oils with formation viscosity greater than 350 mPa•s, conventional cold recovery methods result in low production rates and poor economic returns. To further improve the recovery rate of heavy oil reservoirs after conventional water flooding, researchers are currently focusing on pilot tests of hot water injection flooding. For hot water injection flooding of heavy oil reservoirs, the formation heavy oil needs to be heated to a certain temperature, allowing it to flow freely under these conditions. Therefore, accurately obtaining the critical temperature required for thermal flooding in different heavy oil reservoirs directly affects the possible replacement mode after conventional water flooding of heavy oil. It is an important basis for determining the thermal injection temperature of different heavy oil fields and is related to the effect of thermal recovery.

[0003] Currently, the common method for determining the critical injection temperature for heavy oil hot water flooding is to compare it with development indicators such as cumulative oil production and recovery rate based on numerical simulation results. However, because numerical simulation software cannot accurately characterize the change of the heavy oil start-up pressure gradient with temperature during thermal recovery simulation, it is usually difficult to obtain a specific value of the critical injection temperature. There is currently no mature technical solution for quantitatively obtaining the critical injection temperature for heavy oil hot water flooding. Summary of the Invention

[0004] The purpose of this invention is to overcome the problem of difficulty in obtaining the critical injection temperature for hot water flooding experiments in oil reservoirs in the existing technology, and to provide a method for determining the critical injection temperature for hot water flooding in heavy oil reservoirs. This method has the advantages of being quantifiable and highly operable, and is applicable to the determination of injection and production parameters in thermal recovery of heavy oil reservoirs. It is of great significance for the design of thermal recovery schemes for heavy oil reservoirs.

[0005] To achieve the above objectives, the present invention provides a method for determining the critical injection temperature for hot water flooding in heavy oil reservoirs, comprising the following steps:

[0006] S1. Determine the starting pressure gradient of the simulated heavy oil reservoir hot water flooding experiment at different temperatures and permeabilities, and fit the starting pressure gradient-temperature curve with temperature as the abscissa and starting pressure gradient as the ordinate at the same permeability.

[0007] S2. Determine the critical injection temperature for the hot water flooding experiment of heavy oil reservoir based on the aforementioned starting pressure gradient-temperature curve.

[0008] Preferably, in step S1, the method for determining the starting pressure gradient of the simulated heavy oil reservoir hot water flooding experiment at different temperatures and permeabilities is as follows: the flow rate of the simulated heavy oil reservoir hot water flooding experiment is measured at different temperatures, permeabilities, and pressure gradients, and a pressure gradient-flow rate curve is fitted at the same temperature and permeability. The pressure gradient at the point where the flow rate is greater than 0 mL / min and less than or equal to 0.002 mL / min in the pressure gradient-flow rate curve is taken as the starting pressure gradient of the reservoir at that temperature and permeability.

[0009] More preferably, the pressure gradient is the ratio of the pressure difference between two specific locations to the flow distance of the liquid between the two specific locations.

[0010] More preferably, the two specific locations are the positions of the two ends of the core holder used in the simulated heavy oil reservoir hot water flooding experiment.

[0011] Preferably, in the simulated reservoir hot water flooding experiment, the lower limit of the temperature range is the original formation temperature of the reservoir, and the upper limit of the temperature range is such that the tail end of the obtained starting pressure gradient-temperature curve is parallel to the horizontal axis.

[0012] More preferably, the upper limit of the temperature range is the boiling temperature of water under formation pressure conditions.

[0013] Preferably, in step S2, the method for determining the critical heat injection temperature of the hot water flooding experiment of heavy oil reservoir based on the starting pressure gradient-temperature curve includes: drawing tangents at the two endpoints of the starting pressure gradient-temperature curve, and the abscissa of the intersection of the two tangents is the critical heat injection temperature of the hot water flooding experiment of heavy oil reservoir.

[0014] Preferably, the method further includes: determining the initial viscosity of different crude oil samples, and determining the critical injection temperature under different permeabilities and different initial crude oil viscosities according to steps S1-S2.

[0015] More preferably, a critical heat injection temperature-permeability curve is fitted based on the above permeability and critical heat injection temperature, with permeability as the abscissa and critical heat injection temperature as the ordinate.

[0016] More preferably, a relationship graph between critical heat injection temperature, permeability, and initial viscosity of crude oil is fitted based on the critical heat injection temperature-permeability curve and the initial viscosity of crude oil, and the critical heat injection temperature under different combinations of permeability and initial viscosity of crude oil is determined by the relationship graph.

[0017] The method described above, which uses the reservoir start-up pressure gradient-temperature curve to determine the critical injection temperature for hot water flooding experiments, offers advantages such as quantifiability and high operability. It solves the problems of numerical simulations of thermal recovery failing to accurately characterize the change of reservoir start-up pressure gradient with temperature and failing to quantitatively obtain the critical injection temperature for hot water flooding.

[0018] Moreover, this method has a wide range of applications. It can be used not only to determine the injection and production parameters of thermally recovered oil reservoirs, but also to screen the development methods of heavy oil reservoirs with different viscosities, which is of great significance for the design of reservoir thermal recovery schemes. Attached Figure Description

[0019] Figure 1 This is a pressure gradient-flow rate curve diagram in a specific embodiment of the present invention;

[0020] Figure 2 This is a starting pressure gradient-temperature curve of cores with different permeability in a specific embodiment of the present invention;

[0021] Figure 3 This is a graph showing the critical injection temperature curves for hot water flooding of heavy oil reservoirs with different permeabilities and initial viscosities in a specific embodiment of the present invention.

[0022] Figure 4 This is a graph showing the relationship between critical injection temperature, permeability, and initial viscosity for hot water flooding of heavy oil reservoirs, drawn according to a specific embodiment of the present invention.

[0023] Figure 5 This is a flowchart illustrating the creation of a critical injection temperature chart for hot water flooding in heavy oil reservoirs according to a specific embodiment of the present invention.

[0024] Figure 6 This is a pressure gradient-flow rate curve according to another specific embodiment of the present invention;

[0025] Figure 7 A starting pressure gradient-temperature curve of core samples with different permeability according to another specific embodiment of the present invention;

[0026] Figure 8 This is a graph showing the critical injection temperature curves for hot water flooding of heavy oil reservoirs with different permeabilities and initial viscosities according to another specific embodiment of the present invention.

[0027] Figure 9 This is a graph showing the relationship between critical injection temperature, permeability, and initial viscosity for hot water flooding of heavy oil reservoirs according to another specific embodiment of the present invention. Detailed Implementation

[0028] The endpoints and any values ​​of the ranges disclosed herein are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoint values ​​of the various ranges, the endpoint values ​​of the various ranges and individual point values, and individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed herein.

[0029] As mentioned above, the basic embodiment of the present invention provides a method for determining the critical injection temperature for hydrothermal flooding in oil reservoirs, such as... Figure 5 As shown, it includes the following steps:

[0030] S1. Determine the starting pressure gradient of the simulated heavy oil reservoir hot water flooding experiment at different temperatures and permeabilities, and fit the starting pressure gradient-temperature curve with temperature as the abscissa and starting pressure gradient as the ordinate at the same permeability.

[0031] S2. Determine the critical injection temperature for hot water flooding of heavy oil reservoirs based on the starting pressure gradient-temperature curve.

[0032] According to the present invention, the method for determining the critical injection temperature for hot water flooding of heavy oil reservoirs can be applied to the development of hot water flooding of ordinary heavy oil. Specifically, ordinary heavy oil refers to crude oil with a specific gravity greater than 0.92 and a degassed oil viscosity of 100-10000 mPa∙S.

[0033] The determination method provided in the above-described basic embodiments of the present invention first fits the starting pressure gradient-temperature curve by simulating the starting pressure gradient of a reservoir under different temperatures and permeabilities in a hot water flooding experiment. Then, it determines the critical temperature of the reservoir hot water flooding experiment based on the starting pressure curve. This method has the advantages of being quantifiable and highly operable. It can solve the problems that numerical simulation of thermal recovery cannot accurately characterize the change of reservoir starting pressure gradient with temperature and cannot quantitatively obtain the critical temperature of hot water flooding, which is of great significance for the design of reservoir thermal recovery schemes.

[0034] The method for determining the initiation pressure gradient of a simulated reservoir hydrodynamic flooding experiment at different temperatures and permeabilities can be any method capable of measuring the initiation pressure gradient at different temperatures and permeabilities. In a specific embodiment of the present invention, in step S1, the method for determining the initiation pressure gradient of the simulated reservoir hydrodynamic flooding experiment at different temperatures and permeabilities is as follows: the flow rate of the simulated reservoir hydrodynamic flooding experiment is measured at different temperatures, permeabilities, and pressure gradients, and a pressure gradient-flow rate curve is fitted at the same temperature and permeability. The pressure gradient at the point where the flow rate is greater than 0 mL / min and less than or equal to 0.002 mL / min in the pressure gradient-flow rate curve is taken as the initiation pressure gradient of the reservoir at that temperature and permeability. The initiation pressure gradient determined by the above method is more accurate, thereby making the subsequently obtained critical injection temperature more accurate.

[0035] According to the present invention, the pressure gradient is the ratio of the pressure difference between two specific locations to the flow distance of the liquid between the two specific locations. Specifically, when the liquid flows in a straight line between the two locations, the pressure gradient is the ratio of the pressure difference between the two specific locations to the straight-line distance between the two specific locations; when the liquid flows in a curve between the two specific locations, the pressure gradient is the ratio of the pressure difference between the two specific locations to the actual length of the curve between the two locations. Determining the pressure gradient in this way makes the obtained pressure gradient more accurate, thereby making the subsequently obtained critical heat injection temperature more accurate.

[0036] In one specific embodiment of the present invention, the two specific locations are the two ends of the core holder used to simulate the hot water flooding experiment in an oil reservoir. Limiting the two specific locations to the two ends of the core holder in the simulated hot water flooding experiment ensures that these locations are relatively easy to determine during the experiment. This facilitates the determination of the flow distance of the liquid between these two ends and the determination of the pressure difference between the two ends, thereby making the obtained pressure gradient more accurate, and consequently, making the subsequently obtained critical injection temperature more accurate.

[0037] In one specific embodiment of the present invention, in a simulated reservoir hot water flooding experiment, the lower limit of the temperature range is the original formation temperature of the reservoir (in the following embodiment, the original bottom layer temperature of the reservoir is 50°C), and the upper limit of the temperature range is such that the tail end of the obtained initiation pressure gradient-temperature curve is parallel to the horizontal axis. According to the present invention, the tail end here refers to the tail end of the initiation pressure gradient-temperature curve. For example, when the temperature range of the initiation pressure gradient-temperature curve is 50-180°C, then the tail end of the curve is a curve with a temperature range of 160-180°C, 170-180°C, or 175-180°C. Setting the lower limit of the temperature range to 50°C and the upper limit to make the tail end of the obtained initiation pressure gradient-temperature curve parallel to the horizontal axis allows for a more accurate determination of the critical injection temperature.

[0038] In a relatively preferred embodiment of the present invention, in the simulated reservoir hot water flooding experiment, the upper limit of the temperature range is the boiling temperature of water under formation pressure conditions, which is generally less than 340°C. In the following embodiments, the boiling temperature of water under formation pressure conditions is 180°C or 190°C.

[0039] In one specific embodiment of the present invention, in step S2, the method for determining the critical heat injection temperature of a heavy oil reservoir hot water flooding experiment based on the starting pressure gradient-temperature curve includes: drawing tangents at the two endpoints of the starting pressure gradient-temperature curve, and the x-coordinate of the intersection of the two tangents is the critical heat injection temperature of the reservoir hot water flooding experiment. This method can obtain a more accurate critical heat injection temperature.

[0040] In one specific embodiment of the present invention, the method further includes: determining the initial viscosity of different crude oil samples, and determining the critical injection temperature under different permeabilities and different initial crude oil viscosities according to steps S1-S2. Preferably, a critical injection temperature-permeability curve is fitted based on the above permeability and critical injection temperature, with permeability as the abscissa and critical injection temperature as the ordinate. Preferably, a relationship graph between critical injection temperature, permeability, and initial crude oil viscosity is fitted based on the critical injection temperature-permeability curve and the initial crude oil viscosity, and the critical injection temperature under different combinations of permeability and initial crude oil viscosity is determined through this relationship graph. This method is applicable not only to the determination of injection and production parameters for thermally recovered oil reservoirs, but also to the screening of development methods for heavy oil reservoirs with different viscosities, which is of great significance for the design of reservoir thermal recovery schemes.

[0041] According to a particularly preferred embodiment of the present invention, a method for determining the critical injection temperature for hot water flooding of heavy oil reservoirs is provided, comprising the following steps:

[0042] S1. Measure the flow rate of the simulated heavy oil reservoir hot water flooding experiment at different temperatures, permeabilities and pressure gradients, and fit the pressure gradient-flow rate curve at the same temperature and permeability. In the pressure gradient-flow rate curve, the pressure gradient at the point where the flow rate is greater than 0 mL / min and less than 0.002 mL / min is taken as the starting pressure gradient of the heavy oil reservoir at that temperature and permeability.

[0043] At the same permeability, a starting pressure gradient-temperature curve was fitted with temperature as the abscissa and starting pressure gradient as the ordinate;

[0044] The pressure gradient is the ratio of the pressure difference at the two ends of the core holder used to simulate the hot water flooding experiment of heavy oil reservoir to the flow distance of the liquid between the two ends. In the above measurement process, the lower limit of the temperature range is 50℃ and the upper limit of the temperature range is 180-190℃.

[0045] S2. Draw tangents at the two endpoints (upper temperature limit and lower temperature limit) of the starting pressure gradient-temperature curve. The x-coordinate of the intersection of the two tangents is the critical heat injection temperature for the hot water flooding experiment of heavy oil reservoir.

[0046] S3. Measure the initial viscosity of different crude oil samples, and determine the critical injection temperature under different permeabilities and different initial crude oil viscosities according to steps S1-S2. Based on the above permeability and critical injection temperature, fit a critical injection temperature-permeability curve with permeability as the abscissa and critical injection temperature as the ordinate. Based on the critical injection temperature-permeability curve and the initial crude oil viscosity, fit a relationship graph of critical injection temperature, permeability and initial crude oil viscosity. Determine the critical injection temperature under different combinations of permeability and initial crude oil viscosity through this relationship graph.

[0047] Specifically, a multivariate regression method was used to fit the critical injection temperature-permeability curve and the initial viscosity of crude oil to obtain a graph showing the relationship between the critical injection temperature, permeability and initial viscosity of crude oil.

[0048] The method described in the preferred embodiments of this invention determines the critical injection temperature for hot water flooding experiments in heavy oil reservoirs using the reservoir initiation pressure gradient-temperature curve. This method offers advantages such as quantifiability and high operability. It solves the problems of numerical simulations of thermal recovery failing to accurately characterize the change of reservoir initiation pressure gradient with temperature and failing to quantitatively obtain the critical injection temperature for hot water flooding. Furthermore, this method has a wide range of applications, not only for determining injection and production parameters in thermally recovered reservoirs but also for screening development methods for heavy oil reservoirs of different viscosities, making it significant for reservoir thermal recovery scheme design.

[0049] As a specific embodiment of the present invention, the determination of the critical injection temperature for hot water flooding in heavy oil reservoirs includes the following steps:

[0050] S1. The core in the core holder is saturated with water. Then, heavy oil is used for oil-water displacement until the core in the core holder is completely saturated with oil. Then, water-oil displacement is performed. The pressure difference between the two ends of the core holder can be set to obtain a ΔP. The flow rate Q under this pressure difference is recorded. The pressure difference ΔP is changed to obtain a new flow rate Q and the flow rate Q is recorded. This step is repeated. By setting different ΔP, a series of Q1, Q2, Q3, ... Qn can be obtained. The pressure difference and flow rate data are recorded. One set of data is shown in Table 1 to explore the pressure difference-flow rate relationship.

[0051] Table 1

[0052]

[0053] S2. Convert the experimental pressure difference into a pressure gradient, test the flow rate under different pressure gradients, and plot a pressure gradient-flow rate line graph with the pressure gradient on the x-axis and the flow rate on the y-axis, as shown below. Figure 1 As shown.

[0054] S3. Select the pressure gradient in the pressure gradient-flow rate graph as the starting pressure gradient of the core under the experimental conditions (temperature 70℃, crude oil viscosity 3795mPa∙s, permeability 524mD) where the flow rate is just greater than 0 and less than or equal to 0.002 mL / min.

[0055] S4. Measure the starting pressure gradient of core samples with different permeabilities (e.g., 969 mD, 2784 mD, 4356 mD, 6028 mD, 7806 mD) at different temperatures (e.g., 50℃, 60℃, 70℃, 90℃, 100℃, 110℃, 120℃, 140℃, 150℃, 160℃, 170℃, 180℃), as shown in Table 2. Plot a curve with temperature on the x-axis and starting pressure gradient on the y-axis. Figure 2 .

[0056] Table 2

[0057]

[0058] S5. Draw tangents at both ends of the curve, and take the x-coordinate of the intersection of the two tangents as the critical heat injection temperature. For example, according to the above method, the critical heat injection temperature is determined to be 143℃ when the permeability is 524mD; 134℃ when the permeability is 969mD; and 93℃ when the permeability reaches 7806mD.

[0059] S6. Using a core displacement device and repeating steps S1-S5 above, determine the critical heat injection temperature under different permeabilities (524 mD, 969 mD, 2784 mD, 4356 mD, 6028 mD, 7806 mD) and different oil samples (viscosities of 213 mPa•s, 1160 mPa•s, 3795 mPa•s, 7280 mPa•s, and 10910 mPa•s under reservoir temperature conditions). Determine the variation of critical heat injection temperature with permeability and viscosity. The experimental results are shown in Table 3. Plot a curve with permeability on the x-axis and critical heat injection temperature on the y-axis. The results are as follows: Figure 3 .

[0060] Table 3

[0061]

[0062] S7. Using Shuanghu software, based on the test results of critical heat injection temperatures under different permeabilities and viscosities, a multiple regression method was employed to fit the critical heat injection temperatures with crude oil viscosities (viscosities of 213 mPa·s, 1160 mPa·s, 3795 mPa·s, 7280 mPa·s, and 10910 mPa·s under reservoir temperature conditions) and core permeabilities (524 mD, 969 mD, 2784 mD, 4356 mD, 6028 mD, and 7806 mD). A graph of the inflection point temperature of heavy oil was plotted with permeability on the x-axis and initial viscosity on the y-axis. Figure 4 .

[0063] This chart can be used to determine the critical injection temperature of reservoirs under different combinations of permeability and oil viscosity, providing a reference for determining the temperature of the heating medium and the reasonable range of formation heating temperature, and enabling the rational selection of water injection temperature for heavy oil hot water drive.

[0064] As another specific embodiment of the present invention, the determination of the critical injection temperature for hot water flooding in heavy oil reservoirs includes the following steps:

[0065] S1. The core in the core holder is saturated with water. Then, heavy oil is used for oil-water displacement until the core in the core holder is completely saturated with oil. Then, water-oil displacement is performed. The pressure difference between the two ends of the core holder can be set to obtain a ΔP. The flow rate Q under this pressure difference is recorded. The pressure difference ΔP is changed to obtain a new flow rate Q and the flow rate Q is recorded. This step is repeated. By setting different ΔP, a series of Q1, Q2, Q3, ... Qn can be obtained. The pressure difference and flow rate data are recorded. One set of data is shown in Table 4 to explore the pressure difference-flow rate relationship.

[0066] Table 4

[0067]

[0068] S2. Convert the experimental pressure difference into a pressure gradient, test the flow rate under different pressure gradients, and plot a pressure gradient-flow rate line graph for the heavy oil in this block, with the pressure gradient as the x-axis and the flow rate as the y-axis. Figure 6 As shown.

[0069] S3. Select the pressure gradient in the pressure gradient-flow rate graph as the starting pressure gradient of the core under the experimental conditions (temperature 70℃, crude oil viscosity 5910mPa∙s at reservoir temperature, permeability 500mD), which is just greater than 0 and less than or equal to 0.002 mL / min.

[0070] S4. Measure the starting pressure gradient of core samples with different permeabilities (e.g., 500mD, 1000mD, 2784mD, 4356mD, 5028mD, 6000mD) at different temperatures (e.g., 50℃, 60℃, 70℃, 90℃, 100℃, 110℃, 120℃, 140℃, 150℃, 160℃, 170℃, 180℃, 190℃), as shown in Table 5. Plot a curve with temperature on the x-axis and starting pressure gradient on the y-axis. Figure 7 .

[0071] Table 5

[0072]

[0073] S5. Draw tangents at both ends of the curve, and take the x-coordinate of the intersection of the two tangents as the critical heat injection temperature. For example, according to the above method, it is determined that: when the permeability is 500mD, the critical heat injection temperature is 165℃; when the permeability is 1000mD, the critical heat injection temperature is 145℃; when the permeability reaches 6000mD, the critical heat injection temperature decreases to 95℃.

[0074] S6. Using a core displacement device and repeating steps S1-S5 above, determine the critical heat injection temperature under different permeabilities (524 mD, 969 mD, 2784 mD, 4356 mD, 6028 mD, 7806 mD) and different oil samples (viscosities of 213 mPa•s, 1160 mPa•s, 3795 mPa•s, 7280 mPa•s, and 10910 mPa•s under reservoir temperature conditions). Determine the variation of critical heat injection temperature with permeability and viscosity. The experimental results are shown in Table 6. Plot a curve with permeability on the x-axis and critical heat injection temperature on the y-axis. The results are as follows: Figure 8 .

[0075] Table 6

[0076]

[0077] S7. Using Shuanghu software, based on the test results of critical heating temperatures under different permeabilities and viscosities, a multiple regression method was employed to fit the critical heating temperature with the viscosity of crude oil at 70℃ and the core permeability values. A graph of the critical heating temperature of heavy oil was plotted with permeability on the x-axis and the initial viscosity of the heavy oil on the y-axis, as shown below. Figure 9 .

[0078] This chart can be used to determine the critical injection temperature of reservoirs under different combinations of permeability and oil viscosity, providing a reference for determining the temperature of the heating medium and the reasonable range of formation heating temperature, and enabling the rational selection of water injection temperature for heavy oil hot water drive.

[0079] The preferred embodiments of the present invention have been described in detail above; however, the present invention is not limited thereto. Within the scope of the inventive concept, various simple modifications can be made to the technical solutions of the present invention, including combinations of various technical features in any other suitable manner. These simple modifications and combinations should also be considered as the content disclosed in the present invention and are all within the protection scope of the present invention.

Claims

1. A method for determining the critical injection temperature for hot water flooding in heavy oil reservoirs, characterized in that, Includes the following steps: S1. Measure the flow rate of the simulated heavy oil reservoir hot water flooding experiment at different temperatures, permeabilities, and pressure gradients, and fit the pressure gradient-flow rate curve at the same temperature and permeability. In the pressure gradient-flow rate curve, take the pressure gradient at the point where the flow rate is greater than 0 mL / min and less than or equal to 0.002 mL / min as the starting pressure gradient of the reservoir at that temperature and permeability. Fit the starting pressure gradient-temperature curve with temperature as the abscissa and starting pressure gradient as the ordinate at the same permeability. S2. Draw tangents at the two endpoints of the starting pressure gradient-temperature curve. The x-coordinate of the intersection of the two tangents is the critical heat injection temperature for the hot water flooding experiment in heavy oil reservoirs. S3. Based on the critical heat injection temperature-permeability curve and the initial viscosity of crude oil, fit the relationship graph of critical heat injection temperature, permeability and initial viscosity of crude oil, and determine the critical heat injection temperature under different combinations of permeability and initial viscosity of crude oil through the relationship graph. In the simulated hot water flooding experiment of heavy oil reservoir, the lower limit of the temperature range is the original formation temperature of the reservoir, and the upper limit of the temperature range is such that the tail end of the obtained starting pressure gradient-temperature curve is parallel to the horizontal axis.

2. The method according to claim 1, characterized in that, The pressure gradient is the ratio of the pressure difference between two specific locations to the flow distance of the liquid between the two specific locations; The two specific locations are the positions of the two ends of the core holder used in the simulated heavy oil reservoir hot water flooding experiment.

3. The method according to claim 1 or 2, characterized in that, The upper limit of the temperature range is the boiling temperature of water under formation pressure conditions.

4. The method according to claim 1 or 2, characterized in that, The method further includes: determining the initial viscosity of different crude oil samples, and determining the critical injection temperature under different permeabilities and different initial crude oil viscosities according to steps S1-S2.

5. The method according to claim 4, characterized in that, Based on the above permeability and critical heat injection temperature, a critical heat injection temperature-permeability curve is fitted with permeability on the horizontal axis and critical heat injection temperature on the vertical axis.

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