Method for determining dynamic changes of the proposed start-up pressure gradient in hot water flooding after heavy oil water flooding

Abstract

A method for determining the dynamic change of the proposed start-up pressure gradient when heavy oil is converted to hot water drive after water drive, comprising the following steps: 1. Collecting static data of geological reservoirs in the target block; 2. Determining the relationship between viscosity and temperature of oil samples in the target block; 3. Testing the proposed start-up pressure gradient of cores and oil samples in the target block under different temperature and permeability conditions; 4. Obtaining the relationship between the start-up pressure gradient at different temperatures and fluidity; 5. Obtaining the formation temperature field distribution at different stages of the hot water drive process in the target block; 6. Calculating the start-up pressure gradient according to the geological reservoir parameters of each grid; 7. Drawing the start-up pressure gradient distribution diagram at different stages of hot water drive in the target block. The present invention not only quantitatively characterizes the relationship between the proposed start-up pressure gradient and permeability, viscosity, temperature, etc. of heavy oil reservoirs of different geological reservoir types; but also obtains the formation temperature field distribution at different stages of hot water drive in the target block; and determines the production pressure difference and the critical well spacing of the target block.

Description

Technical Field

[0001] The invention belongs to the field of offshore oil engineering, and in particular relates to a method for determining dynamic changes in a pressure gradient to be started when heavy oil is water-flooded and then converted to hot water flooding. Background Art

[0002] At present, the scale of heavy oil in Bohai Sea is relatively large. For heavy oil reservoirs with crude oil viscosity of about 150-400mPa·s under formation conditions, conventional cold production such as natural energy and water injection is mostly used for development. As for the contradiction between plane and interlayer, it can be basically solved through comprehensive adjustments such as plane well network adjustment and layered system development; however, due to the high viscosity of crude oil, conventional water flooding faces relatively large oil-water mobility; and due to the problem of easy breakthrough of injected water, the problem of low oil recovery efficiency and sweep efficiency has become the main contradiction faced in the middle and late stages of heavy oil reservoir development.

[0003] For heavy oil reservoirs, usually, conventional water flooding is followed by hot water flooding to further improve the recovery rate, which is the focus of current offshore heavy oil thermal recovery. The technology of using conventional water flooding for heavy oil and then switching to hot water flooding to improve the recovery rate is a new technology currently being studied and tested. Its development effect is closely related not only to the shape of the reservoir and the well pattern, but also to parameters such as injection rate and injection-production pressure difference.

[0004] According to current research, the main mechanisms of hot water flooding to increase oil production include:

[0005] 1) Thermal viscosity reduction reduces mobility and improves the fluidity of heavy oil;

[0006] 2) Increase the sweep coefficient and improve the viscous fingering of water flooding;

[0007] 3) Reduce residual oil saturation and improve oil recovery efficiency;

[0008] 4) Reduce interfacial tension;

[0009] 5) Reduce the starting pressure gradient;

[0010] 6) Thermal expansion, etc.

[0011] The proposed starting pressure gradient of heavy oil has a great influence on the seepage law of heavy oil in the formation. Different starting pressure gradients often correspond to different injection-production well spacing and injection-production pressure difference designs.

[0012] The published papers such as "Determination of Reasonable Injection-Production Well Spacing in the Presence of Start-up Pressure Gradient" mainly focus on experimental tests or numerical simulations under constant temperature conditions. However, there are few studies on the influence of injection temperature on geological reservoir parameters (such as crude oil viscosity, permeability, etc.) and quantitative analysis of the dynamic changes of the simulated start-up pressure gradient in the hot water flooding process by analyzing the changes in geological reservoir parameters under high temperature conditions. Summary of the invention

[0013] The present invention aims to provide a method for determining the dynamic change of the simulated start-up pressure gradient when heavy oil water flooding is converted to hot water flooding, so as to solve the influence of injection temperature on geological reservoir parameters (such as crude oil viscosity, permeability, etc.), and to quantitatively analyze the technical problems of the dynamic change of the simulated start-up pressure gradient in the hot water flooding process by analyzing the changes of geological reservoir parameters under high temperature conditions.

[0014] To achieve the above object, the specific technical scheme of the method for determining the dynamic change of the pressure gradient to be started after heavy oil water flooding and then hot water flooding of the present invention is as follows:

[0015] A method for determining the dynamic change of the pressure gradient to be started after heavy oil water flooding and then hot water flooding, comprising the following steps:

[0016] The first step is to collect static data on geological reservoirs in the target area;

[0017] The second step is to determine the relationship between the viscosity and temperature of the oil sample in the target block;

[0018] The third step is to test the simulated start-up pressure gradient of the target block core and oil samples under different temperature and permeability conditions;

[0019] The fourth step is to obtain the relationship between the simulated starting pressure gradient and fluidity under different temperature conditions;

[0020] The fifth step is to obtain the formation temperature field distribution at different stages of the hot water flooding process in the target block;

[0021] Step 6, calculate the proposed start-up pressure gradient according to the geological reservoir parameters of each grid;

[0022] The seventh step is to draw the distribution diagram of the proposed startup pressure gradient at different stages of hot water flooding in the target block.

[0023] Furthermore, in the first step, the static reservoir data is to collect static geological reservoir data such as effective thickness, permeability, porosity, and formation crude oil viscosity of the target block oil layer.

[0024] Furthermore, in the second step, the relationship is as follows:

[0025] ① Collect crude oil samples from the target block and remove dissolved gas;

[0026] ② Test the viscosity of degassed crude oil under different temperature conditions;

[0027] ③ Take the logarithm of the temperature value as the horizontal axis and the double logarithm of the viscosity value as the vertical axis, establish a coordinate system, draw a scatter plot, and fit the heavy oil viscosity μ od The relationship between temperature T:

[0028] LgLgod =C-DLgT (1)

[0029] Where: μ od is the viscosity of degassed crude oil, mPa·s; T is the crude oil temperature, ℃; C is the constant to be regressed, and D is the slope to be regressed.

[0030] Further, in the second step, (1) when a typical heavy oil reservoir crude oil sample is collected, the dissolved gas is removed; the viscosity value of the degassed crude oil under different temperature conditions in the temperature range of 40°C-100°C is tested;

[0031] ⑵ Take the logarithm of the temperature value as the horizontal axis and the double logarithm of the viscosity value as the vertical axis, establish a coordinate system, draw a scatter plot, and fit the heavy oil viscosity μ od The relationship between the temperature and T gives the coefficients C and D as 1.7579 and 0.7529 respectively;

[0032] LgLg od =1.7579-0.7529LgT(R 2 =0.9802) (2).

[0033] Furthermore, in the third step, crude oil samples and cores of the target block are used to perform a simulated start-up pressure gradient test, and simulated start-up pressure gradients of cores at different temperatures and different permeabilities are recorded.

[0034] Furthermore, in the fourth step, the simulated starting pressure gradient G and mobility value K / μ of heavy oil under different temperature conditions are fitted. od The relationship is:

[0035] Data points for the 60°C experimental test:

[0036] G=0.1346-0.0116K / μ od (R 2 =0.9372) (3)

[0037] Data points for the 80°C experimental test:

[0038] G=0.1016-0.0037K / μ od (R 2 =0.9358) (4)

[0039] For the data points of the 100°C experimental test:

[0040] G=0.0894-0.0012K / μ od (R 2 =0.9062) (5)

[0041] Data points for the 120°C experimental test:

[0042] G=0.0858-0.0008K / μ od (R 2 =0.9020) (6)

[0043] Where: G is the simulated start-up pressure gradient, MPa / m; K is the formation permeability, mD; μ od is: viscosity of degassed crude oil, mPa·s.

[0044] Further, in the fifth step, 1. according to the geological reservoir characteristics of the target block, a numerical simulation well group model is established, and according to the actual heat injection parameters, namely, bottom hole heat injection temperature, hot water injection rate, and production-injection ratio, the model is input to predict the formation temperature field distribution at different stages of the hot water flooding process;

[0045] 2. The temperature field of conventional water injection development of heavy oil reservoirs is a constant temperature field. With the increase of conventional water injection years, the temperature field does not change much, and the temperature of the injected water is close to the original formation temperature; while the temperature field of hot water drive is a variable temperature field. The formation temperature field of conventional water injection development of heavy oil reservoirs and hot water drive development after 5 and 10 years is quite different and can be clearly divided into several different temperature field areas.

[0046] Furthermore, in the sixth step, ① the temperature field between the injection and production wells is divided into four areas: zone I, i.e., >100°C area, zone II, i.e., 80°C-100°C, zone III, i.e., 60°C-80°C, and zone IV, i.e., <60°C;

[0047] ② Combining equation (2) in the second step with equations (3), (4), (5), and (6) in the fourth step, and based on the temperature of each grid determined in the fifth step, the following relationship is used to calculate the simulated starting pressure gradient G in different temperature field areas:

[0048] For Zone IV (<60°C):

[0049]

[0050] For Zone III (60℃-80℃):

[0051]

[0052] For Zone II (80℃-100℃):

[0053]

[0054] For Zone I (>100°C):

[0055]

[0056] Furthermore, in the seventh step, (1) the proposed start-up pressure gradient G is defined as a new function, and equations (7), (8), (9), and (10) are substituted into the function calculation to output the proposed start-up pressure gradient at different times;

[0057] (2) The distribution of the proposed start-up pressure for conventional waterflooding development in heavy oil reservoirs is closely related to formation static parameters such as permeability. The lower the permeability, the greater the value of the proposed start-up pressure gradient G.

[0058] (3) The quasi-starting pressure gradient of the hot water flooding process is greatly affected by the temperature and time of hot water injection. As the injection time increases, the quasi-starting pressure gradient G between the injection and production wells gradually decreases;

[0059] (4) According to the size of the proposed starting pressure gradient G, it can be divided into four areas: Zone I, i.e., <0.011 MPa / m area, Zone II, i.e., 0.011-0.050 MPa / m, Zone III, i.e., 0.051-0.090 MPa / m, and Zone IV, i.e., 0.091-0.125 MPa / m.

[0060] The method for determining the dynamic change of the pressure gradient to be started after heavy oil water flooding and then hot water flooding of the present invention has the following advantages:

[0061] 1. Based on the determination of the viscosity-temperature data of the target block heavy oil, the present invention quantitatively characterizes the relationship between the proposed start-up pressure gradient and permeability, viscosity, temperature, etc. of heavy oil reservoirs of different geological reservoir types;

[0062] 2. The present invention obtains the formation temperature field distribution of the target block at different stages of hot water flooding based on numerical simulation software;

[0063] 3. The present invention draws the distribution diagram of the proposed start-up pressure at different hot water flooding stages according to the changes in the proposed start-up pressure gradient and temperature field, thereby determining the production pressure difference and the limit well spacing of the target block;

[0064] 4. The present invention provides a basis for the design of offshore heavy oil water flooding followed by hot water flooding and injection and production regulation;

[0065] 5. The present invention has been applied in a number of heavy oil fields in Bohai Sea, and can provide guidance and reference for the design of hot water injection schemes in heavy oil fields in Bohai Sea. BRIEF DESCRIPTION OF THE DRAWINGS

[0066] Figure 1 A schematic diagram of a process for determining the dynamic change of the pressure gradient to be started up for heavy oil hot water flooding according to the present invention;

[0067] Figure 2 This is a schematic diagram of the fitting relationship between the viscosity and temperature experimental test data points of the target block oil sample of the present invention in a logarithmic coordinate system; (It is the actual graph on the screen)

[0068] Figure 3 It is a schematic diagram of the simulated startup pressure gradient and fluidity scatter diagram and fitting relationship under different temperature conditions of the present invention; (it is the actual graph on the screen)

[0069] Figure 4 This is a schematic diagram of the temperature field distribution of conventional water injection development of heavy oil reservoirs in the present invention; (it is an actual graphic on the screen)

[0070] Figure 5 This is a schematic diagram of the temperature field distribution diagram of the conventional water injection development of the heavy oil reservoir to hot water injection development (hot water injection for 5 years); (It is the actual figure on the screen)

[0071] Figure 6 This is a schematic diagram of the temperature field distribution diagram of the conventional water injection development of the heavy oil reservoir to hot water injection development (10 years of hot water injection flooding); (It is the actual graph on the screen)

[0072] Figure 7 This is a schematic diagram of the proposed start-up pressure distribution for conventional water injection development of heavy oil reservoirs in the present invention; (it is an actual graphic on the screen)

[0073] Figure 8 This is a schematic diagram of the temperature field distribution diagram of the conventional water injection development of the heavy oil reservoir to hot water injection development (hot water injection for 5 years); (It is the actual figure on the screen)

[0074] Fig. 9 This is a schematic diagram of the temperature field distribution diagram of the conventional water injection development of the heavy oil reservoir in the present invention, which is converted to hot water injection development (10 years of hot water injection flooding). (It is the actual graph on the screen) DETAILED DESCRIPTION

[0075] In order to better understand the purpose, structure and function of the present invention, a method for determining the dynamic change of the proposed start-up pressure gradient of hot water flooding after heavy oil water flooding according to the present invention is further described in detail below in conjunction with the accompanying drawings.

[0076] like Figure 1-Figure 9 As shown, the present invention mainly comprises the following steps:

[0077] like Figure 1 As shown, the first step is to collect static data of geological reservoirs in the target block;

[0078] Collect static geological reservoir data such as effective thickness, permeability, porosity, and formation crude oil viscosity of the target block oil layer;

[0079] The second step is to determine the relationship between the viscosity and temperature of the oil sample in the target block;

[0080] ⑴ Collect crude oil samples from the target block and remove dissolved gas;

[0081] ⑵ Test the viscosity of degassed crude oil under different temperature conditions;

[0082] ⑶ Take the logarithm of the temperature value as the horizontal axis and the double logarithm of the viscosity value as the vertical axis, establish a coordinate system, draw a scatter plot, and fit the heavy oil viscosity μ od The relationship between temperature T and

[0083] LgLg od =C-DLgT (1)

[0084] Where: μ od is the viscosity of degassed crude oil, mPa·s; T is the crude oil temperature, ℃; C is the constant to be regressed, and D is the slope to be regressed.

[0085] As shown in Table 1, 1. When a crude oil sample from a typical heavy oil reservoir in Bohai Sea is collected, the dissolved gas is removed; the viscosity values ​​of the degassed crude oil under different temperature conditions are tested in the temperature range of 40°C-100°C;

[0086] Table 1 Crude oil viscosity values ​​of crude oil samples in the target block under different temperature conditions

[0087] Table 1

[0088]

[0089] like Figure 2 As shown, 2. Take the logarithm of the temperature value as the horizontal axis and the double logarithm of the viscosity value as the vertical axis, establish a coordinate system, draw a scatter plot, and fit the heavy oil viscosity μ od The relationship between the temperature and T gives the coefficients C and D as 1.7579 and 0.7529 respectively;

[0090] LgLg od =1.7579-0.7529LgT(R 2 =0.9802) (2)

[0091] The third step is to test the simulated start-up pressure gradient of the target block core and oil samples under different temperature and permeability conditions;

[0092] The crude oil samples and cores of the target block were used to conduct the simulated start-up pressure gradient test, and the simulated start-up pressure gradients of cores with different temperatures and permeabilities were recorded, as shown in Table 2.

[0093] Heavy oil is mainly composed of alkanes, aromatics, and colloid asphaltene. With the increase of colloid and asphaltene content, the relative density and viscosity of heavy oil also increase. The high viscosity of heavy oil is related to its chemical composition structure. The molecular structure belongs to an inhomogeneous colloidal dispersion system, which causes the heavy oil to have the characteristics of a non-Newtonian fluid. The seepage characteristics in porous media are different from those of conventional crude oil. The heavy oil will only start to flow when the displacement pressure gradient exceeds the intended starting pressure gradient.

[0094] Table 2 Pseudo-starting pressure gradient values ​​of different core samples in the target block under different temperature conditions

[0095]

[0096]

[0097] The fourth step is to obtain the relationship between the simulated starting pressure gradient and the fluidity under different temperature conditions; according to the data in Table 1 in the third step, a coordinate system is established with the fluidity value as the horizontal coordinate and the simulated starting pressure gradient value as the vertical coordinate, and a scatter plot is drawn (such as Figure 3 As shown in Figure 2, the simulated starting pressure gradient G and mobility value K / μ of heavy oil under different temperature conditions are fitted. od The relationship is:

[0098] Data points for the 60°C experimental test:

[0099] G=0.1346-0.0116K / μ od (R 2 =0.9372) (3)

[0100] Data points for the 80°C experimental test:

[0101] G=0.1016-0.0037K / μ od (R 2 =0.9358) (4)

[0102] For the data points of the 100°C experimental test:

[0103] G=0.0894-0.0012K / μ od (R 2 =0.9062) (5)

[0104] Data points for the 120°C experimental test:

[0105] G=0.0858-0.0008K / μ od (R 2 =0.9020) (6)

[0106] Where: G is the simulated start-up pressure gradient, MPa / m; K is the formation permeability, mD; μod is: viscosity of degassed crude oil, mPa·s.

[0107] The fifth step is to obtain the formation temperature field distribution at different stages of the hot water flooding process in the target block;

[0108] ⑴ According to the geological reservoir characteristics of the target block, a numerical simulation well group model is established. The actual heat injection parameters (bottom hole heat injection temperature, hot water injection rate, production-injection ratio, etc.) are input into the model to predict the formation temperature field distribution at different stages of the hot water flooding process.

[0109] ⑵ If Figure 4 As shown in the figure, the temperature field of conventional water injection development of heavy oil reservoirs is a constant temperature field. With the increase of conventional water injection years, the temperature field does not change much, and the temperature of the injected water is close to the original formation temperature. The temperature field of hot water flooding is a variable temperature field. The formation temperature field of conventional water injection development of heavy oil reservoirs is different from that of hot water flooding development for 5 years and 10 years, which can be clearly divided into several different temperature field areas (such as Figure 5 and Figure 6 shown).

[0110] In the sixth step, according to the geological reservoir parameters of each grid, the proposed start-up pressure gradient is calculated; according to the temperature of each grid obtained in the fifth step, the temperature field between the injection and production wells is divided into four areas: Area I (>100℃ area), Area II (80℃-100℃), Area III (60℃-80℃), and Area IV (<60℃). Figure 5 , Figure 6 shown).

[0111] Combining the second step equation (2) with the fourth step equations (3), (4), (5), and (6), and based on the temperature of each grid determined in the fifth step, the following relationship is used to calculate the simulated starting pressure gradient G in different temperature field areas.

[0112] For Zone IV (<60°C):

[0113]

[0114] For Zone III (60℃-80℃):

[0115]

[0116] For Zone II (80°C-100°C):

[0117]

[0118] For Zone I (>100°C):

[0119]

[0120] Step 7: Draw the distribution diagram of the proposed startup pressure gradient at different stages of hot water flooding in the target block; in the numerical simulation software, define the proposed startup pressure gradient G as a new function, and substitute equations (7), (8), (9), and (10) into the function calculation. The proposed startup pressure gradient at different times can be output in the numerical simulation software (e.g. Figure 7 , Figure 8 , Fig. 9 shown).

[0121] pass Figure 7 , Figure 8 , Fig. 9 It can be seen that the distribution of the simulated start-up pressure in conventional water injection development of heavy oil reservoirs is closely related to the static parameters of the formation such as permeability. The lower the permeability, the greater the value of the simulated start-up pressure gradient G. The simulated start-up pressure gradient in the hot water flooding process is greatly affected by the temperature and time of the injected hot water. With the extension of the hot injection time, the simulated start-up pressure gradient G between the injection and production wells gradually decreases. According to the size of the simulated start-up pressure gradient G, it can be divided into four areas: Area I (<0.011MPa / m area), Area II (0.011-0.050MPa / m), Area III (0.051-0.090MPa / m), and Area IV (0.091-0.125MPa / m). (For example, Figure 8 , Fig. 9 shown).

[0122] When in use, the present invention quantitatively characterizes the relationship between the proposed start-up pressure gradient and mobility of heavy oil reservoirs of different geological reservoir types on the basis of determining the viscosity-temperature data of the heavy oil in the target block; and obtains the formation temperature field distribution of different stages of hot water flooding in the target block according to the numerical simulation software; and draws the proposed start-up pressure distribution diagram of different hot water flooding stages according to the changes in the proposed start-up pressure gradient and the temperature field, successfully solving the difficult problem in the current industry of determining the dynamic change of the proposed start-up pressure gradient for hot water flooding after water flooding, thereby providing a basis for the well spacing design and injection and production parameter design of the hot water flooding scheme.

[0123] It is to be understood that the present invention is described by some embodiments, and it is known to those skilled in the art that various changes or equivalent substitutions may be made to these features and embodiments without departing from the spirit and scope of the present invention. In addition, under the teachings of the present invention, these features and embodiments may be modified to adapt to specific circumstances and materials without departing from the spirit and scope of the present invention. Therefore, the present invention is not limited by the specific embodiments disclosed herein, and all embodiments falling within the scope of the claims of this application are within the scope of protection of the present invention.

Claims

1. A method for determining the dynamic change of the pressure gradient to be started after heavy oil water flooding and then hot water flooding, It is characterized in that The following steps are involved: The first step is to collect static data on geological reservoirs in the target area; The second step is to determine the relationship between the viscosity and temperature of the oil sample in the target block; The relationship is as follows: ① Collect crude oil samples from the target block and remove dissolved gas; ② Test the viscosity of degassed crude oil under different temperature conditions; ③ Take the logarithm of the temperature value as the horizontal axis and the double logarithm of the viscosity value as the vertical axis, establish a coordinate system, draw a scatter plot, and fit the viscosity μ od The relationship between temperature T is: LgLgμ od =C-DLgT (1); Where: μ od is the viscosity of degassed crude oil, mPa·s; T is the crude oil temperature, °C; C is the constant to be regressed, and D is the slope to be regressed; In the second step, when a crude oil sample of a typical heavy oil reservoir is collected, the dissolved gas is removed; the viscosity of the degassed crude oil is tested at different temperature conditions in the temperature range of 40°C-100°C; Take the logarithm of the temperature value as the horizontal axis and the double logarithm of the viscosity value as the vertical axis, establish a coordinate system, draw a scatter plot, and fit the viscosity μ od The relationship between the temperature and T gives the coefficients C and D as 1.7579 and 0.7529 respectively; LgLgμ od =1.7579-0.7529LgT(R 2 =0.9802) (2); The third step is to test the simulated start-up pressure gradient of the target block core and oil samples under different temperature and permeability conditions; The fourth step is to obtain the relationship between the simulated starting pressure gradient and fluidity under different temperature conditions; In the fourth step, the simulated starting pressure gradient G and mobility value K / μ of heavy oil under different temperature conditions are fitted. od The relationship is: Data points for the 60°C experimental test: G=0.1346-0.0116K / m od (R 2 =0.9372) (3); Data points for the 80°C experimental test: G=0.1016-0.0037K / m od (R 2 =0.9358) (4); For the data points of the 100°C experimental test: G=0.0894-0.0012K / m od (R 2 =0.9062) (5); Data points for the 120°C experimental test: G=0.0858-0.0008K / m od (R 2 (=0.9020) (6); Where: G is the simulated start-up pressure gradient, MPa / m; K is the formation permeability, mD; μ od is: viscosity of degassed crude oil, mPa·s; The fifth step is to obtain the formation temperature field distribution at different stages of the hot water flooding process in the target block; according to the geological reservoir characteristics of the target block, a numerical simulation well group model is established, and the actual heat injection parameters, i.e., bottom hole heat injection temperature, hot water injection rate, and production-injection ratio, are input into the model to predict the formation temperature field distribution at different stages of the hot water flooding process; Step 6, calculate the proposed start-up pressure gradient according to the geological reservoir parameters of each grid; In the sixth step, ① The temperature field between the injection and production wells is divided into four areas: Zone I, i.e., >100℃ area, Zone II, i.e., 80℃-100℃, Zone III, i.e., 60℃-80℃, and Zone IV, i.e., <60℃; ② Combining equation (2) in the second step with equations (3), (4), (5), and (6) in the fourth step, and based on the temperature of each grid determined in the fifth step, the following relationship is used to calculate the simulated starting pressure gradient G in different temperature field areas: For Zone IV (<60°C): For Zone III (60℃-80℃): For Zone II (80°C-100°C): For Zone I (>100°C): The seventh step is to draw the distribution diagram of the proposed startup pressure gradient at different stages of hot water flooding in the target block.

2. The method for determining the dynamic change of the pressure gradient to be started after heavy oil water flooding and then hot water flooding according to claim 1, It is characterized in that In the first step, the static data of geological reservoirs are the effective thickness, permeability, porosity and viscosity of the oil layer in the target block.

3. The method for determining the dynamic change of the pressure gradient to be started after heavy oil water flooding and then hot water flooding according to claim 1, It is characterized in that In the third step, crude oil samples and cores of the target block are used to perform a simulated start-up pressure gradient test, and simulated start-up pressure gradients of cores at different temperatures and different permeabilities are recorded.

4. The method for determining the dynamic change of the pressure gradient to be started after heavy oil water flooding and then hot water flooding according to claim 1, It is characterized in that In the fifth step, The temperature field of conventional water injection development of heavy oil reservoirs is a constant temperature field. With the increase of conventional water injection years, the temperature field does not change much, and the temperature of the injected water is close to the original formation temperature. The temperature field of hot water drive is a variable temperature field. The formation temperature field of heavy oil reservoirs developed by conventional water injection and then switched to hot water drive for 5 and 10 years is quite different and can be clearly divided into several different temperature field areas.

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