Method, device, equipment and medium for inhibiting steam channeling in oil reservoir SAGD development process

Abstract

The invention discloses a method, a device, equipment and a medium for inhibiting steam channeling in an oil reservoir SAGD (steam assisted gravity drainage) development process. The method comprises the following steps: calculating an actual subcool value in the oil reservoir SAGD development process; regulating and controlling measures are adopted based on the actual subcool value to restrain steam channeling; wherein the step of calculating the actual subcool value comprises: calculating a temperature drop value of unit depth; calculating the temperature of the horizontal section based on the temperature drop value of the unit depth; calculating the pressure of the horizontal section; determining the saturation temperature of the horizontal section based on the pressure of the horizontal section; and calculating a difference value between the saturation temperature of the horizontal section and the temperature of the horizontal section, and taking the difference value as an actual subcool value of the horizontal section. According to the method, the actual subcool value can be calculated, so that the production process can be regulated and controlled more accurately to inhibit steam channeling.

Description

Technical Field

[0001] The present invention relates to the technical field of oil reservoir exploitation, and in particular to a method, a device, a equipment and a medium for inhibiting steam channeling in the process of SAGD development of oil reservoirs. Background Art

[0002] SAGD development technology is a cutting-edge technology for developing super-heavy oil. Its production mechanism is to inject high-dryness steam into the steam injection well, and the steam will overlap upward in the formation to form a steam cavity. The steam cavity will expand upward and laterally, and exchange heat with the crude oil in the oil layer. The heated and reduced-viscosity crude oil and steam condensate will be discharged to the horizontal production well below by gravity, and the steam cavity will continue to expand and occupy the volume of crude oil. This technology can greatly reverse the situation of continuous decline in annual oil production due to steam throughput. It has high oil production rate and low production cost, and is one of the thermal recovery technologies with the highest recovery rate. However, due to the deep burial, high formation pressure, small available latent heat of vaporization in the reservoir, and low steam utilization efficiency, SAGD in deep oil reservoirs is difficult to achieve economical and effective development. By optimizing the well pattern and injection and production parameters, SAGD development of deep super-heavy oil reservoirs can be achieved, but improper control of the Subcool value (Subcool refers to the difference between the saturated steam temperature corresponding to the bottom flow pressure of the production well and the actual temperature of the fluid) at different production stages will cause steam channeling and affect the production effect.

[0003] In order to suppress steam channeling, corresponding control measures need to be taken based on the subcool value. However, in the prior art, the subcool value is usually roughly determined by simulation, and the actual subcool value in the production process cannot be accurately understood, resulting in unsatisfactory control effects. Summary of the invention

[0004] The main purpose of the present invention is to provide a method, device, equipment and medium for inhibiting steam channeling during the SAGD development of oil reservoirs, so as to solve the problem that the actual subcooling value in the production process cannot be accurately determined in the prior art, resulting in unsatisfactory control effect.

[0005] According to one aspect of the present invention, a method for inhibiting steam channeling during the SAGD development process of an oil reservoir is provided, comprising:

[0006] Calculate the actual subcool value during SAGD development of oil reservoirs;

[0007] taking control measures to suppress steam breakthrough based on the actual subcool value;

[0008] The calculation of the actual subcool value during the SAGD development of the reservoir includes:

[0009] Calculate the temperature drop value per unit depth based on the actual temperature in the well detected by the well temperature sensor, the actual temperature at the wellhead, and the depth at which the temperature sensor is located;

[0010] Calculating the temperature of the horizontal section based on the actual wellhead temperature, the temperature drop value per unit depth, and the depth of the horizontal section of the well;

[0011] Calculate the pressure of the horizontal section based on the actual pressure in the well detected by the well pressure sensor, the depth of the horizontal section, the depth of the pressure sensor, and the density of the mixed liquid;

[0012] determining a saturation temperature of the horizontal section based on the pressure of the horizontal section;

[0013] The difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment is calculated as the actual subcool value of the horizontal segment.

[0014] According to one embodiment of the present invention, the temperature drop value per unit depth is calculated according to the following formula:

[0015] ΔT=(T1-T0) / H1×k

[0016] Among them, ΔT is the temperature drop value per unit depth; T1 is the actual temperature in the well; T0 is the actual temperature at the wellhead; H1 is the depth where the temperature sensor is located; k is the unit depth.

[0017] According to one embodiment of the present invention, the temperature of the horizontal section is calculated according to the following formula:

[0018] T s =T0+ΔT×H s / k

[0019] Among them, T s is the temperature of the horizontal section; T0 is the actual temperature at the wellhead; ΔT is the temperature drop per unit depth; H s is the depth of the horizontal segment; k is the unit depth.

[0020] According to one embodiment of the present invention, the pressure of the horizontal section is calculated according to the following formula:

[0021] P s =P2+(H s -H2)×ρ / k

[0022] Among them, P s is the pressure of the horizontal section; P2 is the actual pressure in the well; H s is the depth of the horizontal section; H2 is the depth of the pressure sensor; ρ is the density of the mixed liquid; k is the unit depth.

[0023] According to an embodiment of the present invention, the depth of the horizontal segment is an average depth of the horizontal segment.

[0024] According to an embodiment of the present invention, the depth of the horizontal segment includes multiple depths at multiple points on the horizontal segment, and the calculated temperature of the horizontal segment includes multiple temperatures at multiple points on the horizontal segment; and

[0025] The calculating the difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment as the actual subcool value of the horizontal segment includes: calculating the average value of multiple differences between the saturation temperature of the horizontal segment and the temperatures at multiple points on the horizontal segment as the actual subcool value.

[0026] According to an embodiment of the present invention, the temperature sensor and the pressure sensor are arranged on the oil production pump, and the depth at which the temperature sensor is located and the depth at which the pressure sensor is located are both the depth at which the oil production pump is located.

[0027] According to one embodiment of the present invention, the development area includes a first well and a second well, the temperature sensor is disposed in the first well, and the temperature sensor is not disposed in the second well, and the method further includes:

[0028] calculating the temperature drop value per unit depth for each of the plurality of the first wells;

[0029] Determine a linear relationship between the temperature drop value per unit depth and the daily liquid production based on the temperature drop values ​​per unit depth of the plurality of first wells and the daily liquid production of the plurality of first wells;

[0030] Based on the linear relationship and the daily fluid production of the second well, the temperature drop value per unit depth of the second well is calculated.

[0031] According to one embodiment of the present invention, for a well where the pressure sensor is not provided, the actual pressure in the well is calculated according to the following formula:

[0032] P2=×ρ / k

[0033] Among them, 2 is the actual pressure in the well; S is the submergence; k is the unit depth.

[0034] According to an embodiment of the present invention, the method further includes: based on the actual subcool value being higher than a predetermined range, increasing the liquid production of the production well and removing the accumulated liquid.

[0035] According to one embodiment of the present invention, it also includes: based on the actual subcool value being lower than the predetermined range, reducing the liquid production of the production well, adjusting the steam injection well point, thereby restoring the liquid level and suppressing steam channeling.

[0036] According to an embodiment of the present invention, the actual subcool value is compared with different predetermined ranges at different production stages.

[0037] According to one embodiment of the present invention, it also includes: determining the steam cavity development characteristics at different production stages based on the reservoir SAGD model; and taking control measures based on the actual subcool value and the steam cavity development characteristics.

[0038] According to another aspect of the present invention, a device for suppressing steam channeling during the SAGD development process of an oil reservoir is provided, comprising:

[0039] a calculation module configured to calculate actual subcool values ​​during SAGD development of a reservoir;

[0040] a control module configured to take control measures based on the actual subcool value to suppress steam channeling;

[0041] Wherein, the calculation module is configured as follows:

[0042] Calculate the temperature drop value per unit depth based on the actual temperature in the well detected by the well temperature sensor, the actual temperature at the wellhead, and the depth at which the temperature sensor is located;

[0043] Calculating the temperature of the horizontal section based on the actual wellhead temperature, the temperature drop value per unit depth, and the depth of the horizontal section of the well;

[0044] Calculate the pressure of the horizontal section based on the actual pressure in the well detected by the well pressure sensor, the depth of the horizontal section, the depth of the pressure sensor, and the density of the mixed liquid;

[0045] determining a saturation temperature of the horizontal section based on the pressure of the horizontal section;

[0046] The difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment is calculated as the actual subcool value of the horizontal segment.

[0047] According to one embodiment of the present invention, the calculation module is configured to calculate the temperature drop value per unit depth according to the following formula:

[0048] ΔT=(T1-T0) / H1×k

[0049] Among them, ΔT is the temperature drop value per unit depth; T1 is the actual temperature in the well; T0 is the actual temperature at the wellhead; H1 is the depth where the temperature sensor is located; and k is the unit depth.

[0050] According to one embodiment of the present invention, the calculation module is configured to calculate the temperature of the horizontal section according to the following formula:

[0051] T s =T0+ΔT×H s / k

[0052] Among them, T s is the temperature of the horizontal section; T0 is the actual temperature at the wellhead; ΔT is the temperature drop per unit depth; H s is the depth of the horizontal segment; k is the unit depth.

[0053] According to one embodiment of the present invention, the calculation module is configured to calculate the pressure of the horizontal section according to the following formula:

[0054] P s =P2+(H s -H2)×ρ / k

[0055] Among them, P s is the pressure of the horizontal section; P2 is the actual pressure in the well; H s is the depth of the horizontal section; H2 is the depth of the pressure sensor; ρ is the density of the mixed liquid; k is the unit depth.

[0056] According to an embodiment of the present invention, the temperature sensor and the pressure sensor are arranged on the oil production pump, and the depth at which the temperature sensor is located and the depth at which the pressure sensor is located are both the depth at which the oil production pump is located.

[0057] According to another aspect of the present invention, a computer device is provided, comprising:

[0058] at least one processor; and

[0059] A memory, wherein the memory stores a computer program that can be run on the processor, and when the processor executes the program, the method described in any of the above embodiments is implemented.

[0060] According to another aspect of the present invention, a computer-readable storage medium is provided, on which a computer program is stored. When the computer program is executed by a processor, the method described in any one of the above embodiments is implemented.

[0061] Through the technical solution of the present invention, the actual subcool value in the production process can be accurately calculated, so that the production process can be regulated more accurately to suppress steam channeling. BRIEF DESCRIPTION OF THE DRAWINGS

[0062] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0063] Figure 1 A flowchart showing the actual subcool value in the SAGD development process of an oil reservoir according to an embodiment of the present invention is shown;

[0064] Figure 2 The plane and cross-sectional temperature field diagrams of the early stage of the simulated deep SAGD steam chamber development according to an embodiment of the present invention are shown;

[0065] Figure 3 A vector diagram showing the temperature and steam flow velocity in the rising stage of a simulated deep SAGD steam chamber according to an embodiment of the present invention;

[0066] Figure 4 A diagram showing the temperature and volume of the steam chamber during the expansion phase of a simulated deep SAGD steam chamber according to an embodiment of the present invention;

[0067] Figure 5 A temperature field diagram of a simulated deep SAGD steam chamber in a steam chamber decline stage according to an embodiment of the present invention is shown;

[0068] Figure 6 A comparison chart of production indicators at different subcooling temperatures calculated by numerical simulation according to an embodiment of the present invention is shown. DETAILED DESCRIPTION

[0069] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the embodiments of the present invention are further described in detail below in combination with specific embodiments and with reference to the accompanying drawings.

[0070] It should be noted that all expressions using "first" and "second" in the embodiments of the present invention are for distinguishing two non-identical entities with the same name or non-identical parameters. It can be seen that "first" and "second" are only for the convenience of expression and should not be understood as limitations on the embodiments of the present invention. The subsequent embodiments will not explain this one by one.

[0071] The present invention provides a method for inhibiting steam channeling during the SAGD development process of an oil reservoir, comprising: calculating an actual subcool value during the SAGD development process of an oil reservoir; and taking control measures based on the actual subcool value to inhibit steam channeling. Figure 1 A flowchart showing the actual subcool value of the SAGD development process of the reservoir according to an embodiment of the present invention is shown as follows: Figure 1As shown, the actual subcool value during the SAGD development of the reservoir is calculated, including:

[0072] S1, calculating the temperature drop value per unit depth based on the actual temperature in the well detected by the well temperature sensor, the actual temperature at the wellhead and the depth where the temperature sensor is located;

[0073] S2, calculating the temperature of the horizontal section based on the actual temperature of the wellhead, the temperature drop value per unit depth, and the depth of the horizontal section of the well;

[0074] S3, calculating the pressure of the horizontal section based on the actual pressure in the well detected by the well pressure sensor, the depth of the horizontal section, the depth of the pressure sensor, and the density of the mixed liquid;

[0075] S4, determining the saturation temperature of the horizontal section based on the pressure of the horizontal section;

[0076] S5, calculating the difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment as the actual subcool value of the horizontal segment.

[0077] Through the technical solution of the present invention, the actual subcool value in the production process can be accurately calculated, so that the production process can be regulated more accurately to suppress steam channeling.

[0078] In some embodiments, step S1 calculates the temperature drop value per unit depth according to the following formula:

[0079] ΔT=(T1-T0) / H1×k

[0080] Among them, ΔT is the temperature drop value per unit depth; T1 is the actual temperature in the well (°C); T0 is the actual temperature at the wellhead (°C); H1 is the depth of the temperature sensor (specifically, it can be the inclined depth, unit m); k is the unit depth. For example, ΔT can be the temperature drop value per hundred meters, unit is ℃ / 100m; k is 100.

[0081] In some embodiments, step S2 calculates the temperature of the horizontal segment according to the following formula:

[0082] T s =T0+ΔT×H s / k

[0083] Among them, T s is the temperature of the horizontal section (℃); T0 is the actual temperature at the wellhead (℃); ΔT is the temperature drop per unit depth; H s is the depth of the horizontal section (specifically, it can be the inclined depth, in meters); k is the unit depth. For example, ΔT can be the temperature drop value per 100 meters, in degrees Celsius / 100m; k is 100.

[0084] In some embodiments, step S3 calculates the pressure of the horizontal segment according to the following formula:

[0085] P s =P2+(H s -H2)×ρ / k

[0086] Among them, P s is the pressure of the horizontal section (MPa); P2 is the actual pressure in the well (MPa); H s is the depth of the horizontal section (specifically, it can be the vertical depth, in m); H2 is the depth of the pressure sensor (for example, the vertical depth, in m); ρ is the density of the mixed liquid (g / m 3 ); k is the unit depth, for example 100.

[0087] In some embodiments, the temperature sensor and the pressure sensor are arranged on the oil production pump, and the depth of the temperature sensor and the depth of the pressure sensor are both the depth of the oil production pump (where the oblique depth is used when calculating ΔT, and the depth of the pressure sensor is used when calculating P s The actual temperature in the well detected by the temperature sensor can be called the pump-down temperature, and the actual pressure in the well detected by the pressure sensor can be called the pump-down pressure.

[0088] In some embodiments, the depth of the horizontal segment (e.g., oblique depth) is the average depth of the horizontal segment (e.g., average oblique depth), and the depths at multiple points on the horizontal segment can be averaged to obtain the average depth. In other embodiments, the depth of the horizontal segment (e.g., oblique depth) includes multiple depths at multiple points on the horizontal segment (e.g., multiple oblique depths at multiple points), and the calculated temperature of the horizontal segment includes multiple temperatures at multiple points on the horizontal segment; and the calculation of the difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment as the actual subcool value of the horizontal segment includes: calculating the average of multiple differences between the saturation temperature of the horizontal segment and the temperatures at multiple points on the horizontal segment as the actual subcool value. The points on the horizontal segment include, for example, point A of the heel.

[0089] In some embodiments, the development area includes a first well and a second well, the temperature sensor is disposed in the first well, and the temperature sensor is not disposed in the second well, and the method further includes:

[0090] calculating the temperature drop value per unit depth for each of the plurality of the first wells;

[0091] Determine a linear relationship between the temperature drop value per unit depth and the daily liquid production based on the temperature drop values ​​per unit depth of the plurality of first wells and the daily liquid production of the plurality of first wells;

[0092] Based on the linear relationship and the daily fluid production of the second well, the temperature drop value per unit depth of the second well is calculated.

[0093] After calculating all the temperature drop values ​​per 100 meters for the wells with pump-down tests, a scatter plot of the temperature drop per 100 meters and the daily liquid production of the well can be drawn to obtain a relationship chart of the temperature drop per 100 meters and the daily liquid production applicable to the block. By adding a trend line, a linear relationship formula between the temperature drop per 100 meters and the daily liquid production can be obtained. For the wells in the block that lack pump-down test data, the temperature drop value per 100 meters of the well can be converted according to the daily liquid production of the well.

[0094] In some embodiments, for a well without the pressure sensor, the actual pressure in the well is calculated according to the following formula:

[0095] P2=S×ρ / k

[0096] Among them, P2 is the actual pressure in the well; S is the submergence; k is the unit depth.

[0097] Therefore, for wells without pump down test data, the pump down pressure can be converted according to this formula.

[0098] In step S4, for example, the saturation temperature corresponding to the pressure of the horizontal section can be found according to "Thermodynamic Properties Diagram of Water and Water Vapor" written by Yan Jialu and Yu Xiaofu.

[0099] In some embodiments, the method further includes: based on the actual subcool value being higher than the predetermined range (at this time, the liquid level above the production well rises, affecting the expansion of the steam cavity), taking control measures to increase the liquid production of the production well and remove the accumulated liquid. In some embodiments, the method further includes: based on the actual subcool value being lower than the predetermined range (at this time, the liquid level above the production well drops, which is likely to cause steam breakthrough), taking measures to reduce the liquid production of the production well and adjust the steam injection well point, thereby restoring the liquid level and inhibiting steam channeling.

[0100] In some embodiments, the actual subcool value is compared with different predetermined ranges at different production stages, so as to perform corresponding regulation according to the developmental characteristics of different production stages.

[0101] In some embodiments, the method further includes: determining the steam cavity development characteristics at different production stages based on the reservoir SAGD model; and taking control measures based on the actual subcool value and the steam cavity development characteristics. For example, the production stages can be divided by analyzing the formation and expansion law of the steam cavity in the SAGD development of deep ultra-heavy oil reservoirs, giving a reasonable range of Subcool at different stages, and calculating the actual Subcool value based on the Subcool calculation method and comparing it with the reasonable range, and taking corresponding control measures according to the comparison results, thereby ensuring that the SAGD oil production continues to increase while also improving the ultimate recovery rate of the reservoir, maximizing the use (development) of such deep ultra-heavy oil reservoirs, and tapping the maximum value of petroleum, a non-renewable resource.

[0102] In some embodiments, a numerical simulation model of a typical well group of a deep extra-heavy oil reservoir SAGD can be established to describe the development law and production characteristics of the deep SAGD steam chamber at different development stages in detail based on detailed historical matching, including the formation and rising stage of the steam chamber, the expansion stage of the steam chamber, and the decline stage of the steam chamber.

[0103] For example, Figure 2 The developmental characteristics of the steam chamber during its formation stage are shown, such as Figure 2 As shown in the figure, thermal connection has been formed between the injection and production wells, the temperature between the vertical well and the horizontal well exceeds 80°C, the crude oil between the wells has a certain fluidity, the reservoir pressure is low, and the pressure in the well group area is 2.0-2.5MPa. The numerical simulation results show that a steam cavity has been formed around the injection well 20 days after steam injection, and the steam cavity is small.

[0104] Figure 3 The development characteristics of the steam chamber during the ascending stage are shown, such as Figure 3 As shown in the figure, the steam chamber develops above the reservoir under the overlying effect, and first expands along the direction of thermal connectivity advantage; the vertical expansion speed of the steam chamber is slightly better than the planar expansion speed. The steam chamber of a single well has gradually risen to the top of the oil layer; the steam chamber is well developed in the vertical and horizontal well sections, and is locally distributed in a continuous state; while in the horizontal well section direction, the steam chamber is only a single point in form, without continuous development, which lasted about 15 months.

[0105] Figure 4 The developmental characteristics of the steam chamber at the expansion stage are shown, such as Figure 4 As shown in the figure, after the steam chamber of a single well reaches the top of the oil layer, it begins to expand laterally, starting to coalesce from a dispersed state, and eventually forming a steam chamber with multiple inverted cones with a continuous top, which lasts for 33 months.

[0106] Figure 5 The development characteristics of the steam chamber during the descent stage are shown, such as Figure 5As shown in Figure 1, the steam chamber slowly develops downward from the boundaries of both sides of the oil layer top, and finally the area above the horizontal production well is basically filled with the steam chamber, which takes 32 months.

[0107] As mentioned above, the present invention provides a calculation formula for the Subcool value and a method for making the required chart. The actual temperature drop per 100 meters is obtained based on the pump pressure, temperature and other data of the well with pump test data, and a chart of the actual temperature drop per 100 meters of the block and the daily liquid production of the well is drawn.

[0108] The present invention can reasonably optimize the Sub-Cool of production wells for deep extra-heavy oil reservoirs SAGD. It can ensure that the SAGD well group has a higher oil production, a higher oil production rate and a higher oil-gas ratio, achieve a dual improvement in SAGD development effect and economic benefits, and improve the ultimate recovery rate of the oil reservoir. For example, the Sub-Cool of production wells for deep extra-heavy oil reservoirs SAGD can be proposed based on a numerical simulation model. Figure 5 As shown in the figure, when the Subcool monitoring temperature exceeds 30℃, the recovery rate decreases. Therefore, it is determined that the Subcool of the production well should be less than 30℃. By reasonably controlling the Subcool value at different stages, better development effects can be obtained, that is, 15-30℃ in the early stage and 5-15℃ in the later stage.

[0109] The present invention also provides a device for inhibiting steam channeling during the SAGD development process of an oil reservoir, comprising:

[0110] a calculation module configured to calculate actual subcool values ​​during SAGD development of a reservoir;

[0111] a control module configured to take control measures based on the actual subcool value to suppress steam channeling;

[0112] Wherein, the calculation module is configured as follows:

[0113] Calculate the temperature drop value per unit depth based on the actual temperature in the well detected by the well temperature sensor, the actual temperature at the wellhead, and the depth at which the temperature sensor is located;

[0114] Calculating the temperature of the horizontal section based on the actual wellhead temperature, the temperature drop value per unit depth, and the depth of the horizontal section of the well;

[0115] Calculate the pressure of the horizontal section based on the actual pressure in the well detected by the well pressure sensor, the depth of the horizontal section, the depth of the pressure sensor, and the density of the mixed liquid;

[0116] determining a saturation temperature of the horizontal section based on the pressure of the horizontal section;

[0117] The difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment is calculated as the actual subcool value of the horizontal segment.

[0118] In some embodiments, the calculation module is configured to calculate the temperature drop value per unit depth according to the following formula:

[0119] ΔT=(T1-T0) / H1×k

[0120] Among them, ΔT is the temperature drop value per unit depth; T1 is the actual temperature in the well; T0 is the actual temperature at the wellhead; H1 is the depth where the temperature sensor is located; and k is the unit depth.

[0121] In some embodiments, the calculation module is configured to calculate the temperature of the horizontal segment according to the following formula:

[0122] T s =T0+ΔT×H s / k

[0123] Among them, T s is the temperature of the horizontal section; T0 is the actual temperature at the wellhead; ΔT is the temperature drop per unit depth; H s is the depth of the horizontal segment; k is the unit depth.

[0124] In some embodiments, the calculation module is configured to calculate the pressure of the horizontal segment according to the following formula:

[0125] P s =P2+(H s -H2)×ρ / k

[0126] Among them, P s is the pressure of the horizontal section; P2 is the actual pressure in the well; H s is the depth of the horizontal section; H2 is the depth of the pressure sensor; ρ is the density of the mixed liquid; k is the unit depth.

[0127] In some embodiments, the temperature sensor and the pressure sensor are arranged on the oil production pump, and the depth at which the temperature sensor is located and the depth at which the pressure sensor is located are both the depth at which the oil production pump is located.

[0128] The present invention further proposes a computer device, comprising: at least one processor; and a memory, wherein the memory stores a computer program that can be run on the processor, and when the processor executes the program, the method described in any of the above embodiments is implemented.

[0129] The present invention further provides a computer-readable storage medium on which a computer program is stored. When the computer program is executed by a processor, the method described in any of the above embodiments is implemented.

[0130] It should be noted that a person skilled in the art can understand that all or part of the processes in the above-mentioned embodiment methods can be implemented by instructing related hardware through a computer program, and the program can be stored in a computer-readable storage medium. When the program is executed, it can include the processes of the embodiments of the above-mentioned methods.

[0131] Furthermore, it should be appreciated that the computer-readable storage medium (eg, memory) herein may be either a volatile memory or a nonvolatile memory, or may include both volatile and nonvolatile memory.

[0132] A person skilled in the art should understand that the discussion of any of the above embodiments is only exemplary and is not intended to imply that the scope of the disclosure of the embodiments of the present invention (including the claims) is limited to these examples; under the concept of the embodiments of the present invention, the technical features in the above embodiments or different embodiments can also be combined, and there are many other changes in different aspects of the embodiments of the present invention as described above, which are not provided in detail for the sake of simplicity. Therefore, any omissions, modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the embodiments of the present invention should be included in the protection scope of the embodiments of the present invention.

Claims

1. A method for inhibiting steam channeling during the SAGD development of oil reservoirs, characterized in that: include: Calculate the actual subcool value during SAGD development of oil reservoirs; taking control measures to suppress steam breakthrough based on the actual subcool value; The calculation of the actual subcool value during the SAGD development of the reservoir includes: Calculate the temperature drop value per unit depth based on the actual temperature in the well detected by the well temperature sensor, the actual temperature at the wellhead, and the depth at which the temperature sensor is located; Calculating the temperature of the horizontal section based on the actual wellhead temperature, the temperature drop value per unit depth, and the depth of the horizontal section of the well; Calculate the pressure of the horizontal section based on the actual pressure in the well detected by the well pressure sensor, the depth of the horizontal section, the depth of the pressure sensor, and the density of the mixed liquid; determining a saturation temperature of the horizontal section based on the pressure of the horizontal section; The difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment is calculated as the actual subcool value of the horizontal segment.

2. The method according to claim 1, characterized in that: The temperature drop per unit depth is calculated according to the following formula: ΔT=(T1-T0) / H1×k Among them, ΔT is the temperature drop value per unit depth; T1 is the actual temperature in the well; T0 is the actual temperature at the wellhead; H1 is the depth where the temperature sensor is located; and k is the unit depth.

3. The method according to claim 1, characterized in that The temperature of the horizontal section is calculated according to the following formula: T s =T0+ΔT×H s / k Among them, T s is the temperature of the horizontal section; T0 is the actual temperature at the wellhead; ΔT is the temperature drop per unit depth; H s is the depth of the horizontal segment; k is the unit depth.

4. The method according to claim 1, characterized in that: The pressure of the horizontal section is calculated according to the following formula: P s =P2+(H s -H2)×ρ / k Among them, P s is the pressure of the horizontal section; P2 is the actual pressure in the well; H s is the depth of the horizontal section; H2 is the depth of the pressure sensor; ρ is the density of the mixed liquid; k is the unit depth.

5. The method according to claim 1, characterized in that: The depth of the horizontal segment is the average depth of the horizontal segment.

6. The method according to claim 1, characterized in that The depth of the horizontal segment includes a plurality of depths at a plurality of points on the horizontal segment, and the calculated temperature of the horizontal segment includes a plurality of temperatures at a plurality of points on the horizontal segment; as well as The calculating the difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment as the actual subcool value of the horizontal segment includes: calculating the average value of multiple differences between the saturation temperature of the horizontal segment and the temperatures at multiple points on the horizontal segment as the actual subcool value.

7. The method according to claim 1, characterized in that The temperature sensor and the pressure sensor are arranged on the oil production pump, and the depth at which the temperature sensor is located and the depth at which the pressure sensor is located are both the depth at which the oil production pump is located.

8. The method according to claim 1, characterized in that The development area includes a first well and a second well, the temperature sensor is disposed in the first well, and the temperature sensor is not disposed in the second well, and the method further includes: calculating the temperature drop value per unit depth for each of the plurality of the first wells; Determine a linear relationship between the temperature drop value per unit depth and the daily liquid production based on the temperature drop values ​​per unit depth of the plurality of first wells and the daily liquid production of the plurality of first wells; Based on the linear relationship and the daily fluid production of the second well, the temperature drop value per unit depth of the second well is calculated.

9. The method according to claim 1, characterized in that: For a well without the pressure sensor, the actual pressure in the well is calculated according to the following formula: P2=S×ρ / k Among them, P2 is the actual pressure in the well; S is the submergence; k is the unit depth.

10. The method according to claim 1, characterized in that Also includes: Based on the actual subcool value being higher than the predetermined range, the liquid production of the production well is increased to remove the accumulated liquid.

11. The method according to claim 10, characterized in that Also includes: Based on the fact that the actual subcool value is lower than the predetermined range, the liquid production of the production well is reduced and the steam injection well point is adjusted to restore the liquid level and suppress steam channeling.

12. The method according to claim 11, characterized in that The actual subcool value is compared with different predetermined ranges at different production stages.

13. The method according to claim 1, characterized in that Also includes: Determine the characteristics of steam cavity development at different production stages based on the reservoir SAGD model; Control measures are taken based on the actual subcool value and the vapor cavity development characteristics.

14. A device for inhibiting steam channeling during the SAGD development of oil reservoirs, characterized in that: include: a calculation module configured to calculate actual subcool values ​​during SAGD development of a reservoir; a control module configured to take control measures based on the actual subcool value to suppress steam channeling; Wherein, the calculation module is configured as follows: Calculate the temperature drop value per unit depth based on the actual temperature in the well detected by the well temperature sensor, the actual temperature at the wellhead, and the depth at which the temperature sensor is located; Calculating the temperature of the horizontal section based on the actual wellhead temperature, the temperature drop value per unit depth, and the depth of the horizontal section of the well; Calculate the pressure of the horizontal section based on the actual pressure in the well detected by the well pressure sensor, the depth of the horizontal section, the depth of the pressure sensor, and the density of the mixed liquid; determining a saturation temperature of the horizontal section based on the pressure of the horizontal section; The difference between the saturation temperature of the horizontal segment and the temperature of the horizontal segment is calculated as the actual subcool value of the horizontal segment.

15. The device according to claim 14, characterized in that The calculation module is configured to calculate the temperature drop value per unit depth according to the following formula: ΔT=(T1-T0) / H1×k Among them, ΔT is the temperature drop value per unit depth; T1 is the actual temperature in the well; T0 is the actual temperature at the wellhead; H1 is the depth where the temperature sensor is located; and k is the unit depth.

16. The device according to claim 14, characterized in that The calculation module is configured to calculate the temperature of the horizontal section according to the following formula: T s =T0+ΔT×H s / k Among them, T s is the temperature of the horizontal section; T0 is the actual temperature at the wellhead; ΔT is the temperature drop per unit depth; H s is the depth of the horizontal segment; k is the unit depth.

17. The device according to claim 14, characterized in that The calculation module is configured to calculate the pressure of the horizontal section according to the following formula: P s =P2+(H s -H2)×ρ / k Among them, P s is the pressure of the horizontal section; P2 is the actual pressure in the well; H s is the depth of the horizontal section; H2 is the depth of the pressure sensor; ρ is the density of the mixed liquid; k is the unit depth.

18. The device according to claim 14, characterized in that The temperature sensor and the pressure sensor are arranged on the oil production pump, and the depth at which the temperature sensor is located and the depth at which the pressure sensor is located are both the depth at which the oil production pump is located.

19. A computer device comprising: at least one processor; as well as A memory storing a computer program executable on the processor, wherein the processor implements the method according to any one of claims 1 to 13 when executing the program.

20. A computer-readable storage medium having a computer program stored thereon, characterized in that: When the computer program is executed by a processor, the method according to any one of claims 1 to 13 is implemented.

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