A method and device for separate layer and section steam injection in a thermal recovery well

Abstract

The application discloses a kind of thermal recovery well layering segmented steam injection method and device, wherein method includes: obtaining the well data of target well, well data includes reservoir physical property distribution data, steam injection capacity data and test data;According to the well data, the heating zone radius is calculated, and the layer segment injection proportion model is established with the heating zone radius consistency as standard, and the layer segment is divided according to the layer segment injection proportion model and the fluid injection proportion of each layer segment is calculated;According to wellbore variable mass two-phase flow heat transfer model, obtain the wellbore fluid property parameter variation curve;According to the fluid injection amount of each layer segment, wellbore fluid property parameter variation curve determines the valve hole number of each layer segment and is uniformly arranged;According to the formulated layer segment steam injection scheme, each layer segment steam injection operation is carried out.The application realizes the uniform use of different layer segments, expands the steam injection swept area of heavy oil reservoir, effectively suppresses the steam channeling / water channeling phenomenon, and further helps to improve steam injection quality, oil layer producing degree, oil well production and recovery efficiency.

Description

Technical Field

[0001] This invention relates to the field of oilfield development technology, specifically to a method and apparatus for layered and segmented steam injection in thermal recovery wells. Background Technology

[0002] The annual oil production is projected to reach 180 million tons from 2023 to 2030. Due to the abundant heavy oil resources in the Bohai Oilfield, thermal recovery development will play an increasingly important role in future oil production, and its share will significantly increase.

[0003] Currently, steam injection remains the primary method for developing heavy oil reservoirs in China. However, for vertical / directional wells (with large vertical spans) and horizontal wells (with long horizontal sections), traditional general steam injection suffers from problems such as poor injection efficiency, uneven inter-layer utilization, and susceptibility to steam channeling. These problems will become increasingly severe with the increase in the number of injection cycles. Due to formation heterogeneity, uneven steam absorption in high- and low-permeability layers easily leads to steam channeling and water flooding, causing increased water cut in production wells and a decline in exploitation potential. Summary of the Invention

[0004] In view of the above problems, the present invention is proposed to provide a method and apparatus for layered and segmented steam injection in thermal recovery wells to overcome the problem of poor steam injection effect.

[0005] According to one aspect of the present invention, a method for stratified and segmented steam injection in a thermal recovery well is provided, comprising:

[0006] Step 1: Obtain well data for the target well, including reservoir physical property distribution data, steam injection capacity data, and test data;

[0007] Step 2: Calculate the radius of the heating zone based on the well data, establish a segment injection ratio model based on the consistency of the heating zone radius, divide the segments according to the segment injection ratio model and calculate the fluid injection ratio of each segment;

[0008] Step 3: Obtain the variation curves of fluid properties in the wellbore based on the variable mass two-phase flow heat transfer model in the wellbore;

[0009] Step 4: Determine the number of valve holes in each section based on the fluid injection volume and wellbore fluid property parameter variation curves, and arrange them evenly.

[0010] Step 5: Carry out steam injection operations for each layer according to the established layer steam injection plan.

[0011] In an optional approach, the step of dividing the fluid into segments according to the segmented fluid distribution ratio model and calculating the fluid distribution ratio for each segment further includes:

[0012] The derivative of the inter-layer grade difference is obtained by differentiating the grade distribution ratio model.

[0013] Based on the change in the derivative of the inter-layer difference between adjacent layers, adjacent layers are distinguished or merged.

[0014] The fluid distribution ratio of each segment is obtained through the segment distribution ratio model.

[0015] In an alternative approach, dividing the layers according to the layer allocation ratio model further includes:

[0016] Based on the established layer-by-layer injection ratio model, the layer division is achieved using the interlayer differential derivative discrimination principle. The meaning of the interlayer differential derivative is the change in the injection ratio between the current layer and the previous layer. The larger the value, the greater the change in the injection amount required for the current layer to ensure consistent heating radius, and thus the greater the change in its physical properties.

[0017] Based on the obtained reservoir physical property distribution data, calculate the permeability difference, porosity difference, reservoir thickness difference, oil saturation difference, and formation crude oil viscosity difference of each layer.

[0018] The derivative of each segment is calculated using the formula for the derivative of the inter-segment difference. By comparing the magnitudes of the derivatives of the inter-segment differences between adjacent segments, adjacent segments are distinguished or merged.

[0019] In an optional embodiment, obtaining the fluid distribution ratio of each segment after division through the segment distribution ratio model further includes:

[0020] The physical property parameters of the newly merged segments are obtained by weighted averaging, the difference in the physical property parameters of each segment is calculated, and the fluid allocation ratio of each segment after division is calculated by the segment allocation ratio model.

[0021] In one alternative approach, the reservoir property distribution data includes one or more of the following: permeability, porosity, reservoir thickness, oil saturation, and formation crude oil viscosity for each segment.

[0022] The steam injection capacity data includes one or more of the following: wellhead pressure, wellhead temperature, wellhead steam dryness, steam injection flow rate, and total steam injection volume;

[0023] The test data includes one or more of the following: well trajectory data, casing and screen specifications and dimensions, installation location of layered and segmented packers, geothermal gradient, and annular medium type.

[0024] In an alternative approach, obtaining the wellbore fluid property parameter variation curves based on the wellbore variable mass two-phase flow heat transfer model further includes:

[0025] A variable mass two-phase flow heat transfer model for wellbore is established, which considers the changes in steam dryness, the changes in fluid flow rate in the orifice section, and the influence of non-condensate gas injection in the annulus. The model includes a constant mass two-phase flow heat transfer model in the non-orifice section and a variable mass two-phase flow heat transfer model in the orifice section.

[0026] In an optional embodiment, the constant-mass two-phase flow heat transfer model in the non-aperture section and the variable-mass two-phase flow heat transfer model in the aperture section further include: mass conservation equation, momentum conservation equation and energy conservation equation.

[0027] The mass conservation equation is used to calculate the flow rate changes of the gas and liquid phases during a flow process. The optimized formula is shown below:

[0028]

[0029] Among them, G l G g These represent the liquid and gas mass flow rates within the wellbore, respectively; δm i This represents the total mass change of the gas-liquid two-phase fluid in the wellbore.

[0030] The momentum conservation equation is used to calculate the pressure drop along the wellbore during flow. The optimized formula is shown below:

[0031]

[0032] Where f is the two-phase flow friction coefficient, determined by manifold discrimination and calculation using the Beggs-Brill model; w is the flow velocity inside the pipe; and ρ is the gas-liquid two-phase density, ρ = xρ g +(1-x)ρ l x represents steam dryness; ρ g ρ l These represent the gas phase density and liquid phase density, respectively; d is the inner diameter of the tubing; θ is the angle between the directional well section and the horizontal plane, with 0 for the horizontal section; g is the acceleration due to gravity.

[0033] The energy conservation equation is used to calculate the heat transfer along the wellbore and the changes in fluid temperature, dryness fraction, and enthalpy during two-phase flow. The optimized formula is shown below:

[0034]

[0035]

[0036]

[0037]

[0038] w g w lThese represent the gas phase fluid velocity and the liquid phase fluid velocity, respectively; h g h l These are the enthalpy values ​​of the gas phase fluid and the liquid phase fluid, respectively; T in T represents the steam temperature inside the oil pipe. f Formation temperature; K d d is the heat transfer coefficient from the tubing to the formation; di d is the inner diameter of the oil pipe. do d is the outer diameter of the oil pipe. ci d is the inner diameter of the casing. co d is the outer diameter of the casing. h The outer diameter of the cement ring or screen tube; α di λ is the convective heat transfer coefficient between the steam and the inner wall of the oil pipe; p λ is the thermal conductivity of the oil pipe; b λ is the thermal conductivity of the sleeve; cem R is the thermal conductivity of the cement ring or screen tube. e and R f These are the annular thermal resistance and the formation thermal resistance, respectively.

[0039] The step of obtaining the wellbore fluid property parameter variation curve based on the wellbore variable mass two-phase flow heat transfer model further includes: obtaining the wellbore fluid property parameter variation curve based on the fluid property parameter calculation model and the wellbore variable mass two-phase flow heat transfer model.

[0040] In an alternative approach, determining the number of valve orifices for each section based on the fluid injection volume and wellbore fluid property parameter variation curves, and then uniformly arranging them, further includes:

[0041] The pressure difference between the two sides of the steam injection hole is obtained based on the change curve of the fluid properties in the wellbore.

[0042] The outlet flow velocity is obtained based on the pressure difference and fluid density on both sides of the steam injection port. The number of injection valves and valve ports required for each layer are determined based on the preset injection valve orifice diameter and injection volume. The injection volume is determined based on the fluid injection ratio of each layer.

[0043] In one alternative approach, the model for the outlet flow velocity is:

[0044] c 2 =2(p2-p1) / ρ

[0045] Where c is the outlet velocity, p1 and p2 are the pressure differences on both sides of the steam injection hole, and ρ is the fluid density.

[0046] The relationship between the injection volume and the flow rate of each outlet is as follows:

[0047]

[0048] Where Q is the dispensing volume and n is the number of valve orifices, Q i Q represents the flow rate at each outlet. i =πd 2 c / 4, where d is the orifice diameter of the dispensing valve.

[0049] According to another aspect of the present invention, a stratified and segmented steam injection device for thermal recovery wells is provided, comprising:

[0050] The well data acquisition module is used to acquire well data of the target well, including reservoir physical property distribution data, steam injection capacity data, and test data.

[0051] The injection ratio calculation module is used to calculate the radius of the heating zone based on the well data, establish a segment injection ratio model with the heating zone radius being consistent as the standard, divide the segments according to the segment injection ratio model, and calculate the fluid injection ratio of each segment.

[0052] The physical property parameter calculation module is used to obtain the variation curves of the physical property parameters of the wellbore fluid based on the variable mass two-phase flow heat transfer model of the wellbore.

[0053] The valve orifice quantity calculation module is used to determine the number of valve orifices in each section based on the fluid injection volume and wellbore fluid property parameter variation curves, and to evenly distribute them so as to carry out steam injection construction operations in each section according to the established steam injection plan.

[0054] The solution provided in the above embodiments of the present invention obtains well data of the target well, including reservoir physical property distribution data, steam injection capacity data, and test data; calculates the heating zone radius based on the well data, establishes a layer-by-layer injection ratio model based on the uniformity of the heating zone radius, divides the well into layers according to the layer-by-layer injection ratio model, and calculates the fluid injection ratio of each layer; obtains the wellbore fluid physical property parameter variation curves based on the wellbore variable mass two-phase flow heat transfer model; determines the number of valve holes in each layer based on the fluid injection volume and wellbore fluid physical property parameter variation curves, and arranges them uniformly; and performs steam injection operations in each layer according to the established layer-by-layer steam injection plan. The present invention achieves uniform utilization of different layers, expands the steam injection sweep range of heavy oil reservoirs, effectively suppresses steam / water channeling, and thus improves the reservoir utilization, well production, and recovery rate.

[0055] The above description is merely an overview of the technical solution of the present invention. In order to better understand the technical means of the present invention and to implement it in accordance with the contents of the specification, and to make the above description and other objects, features and advantages of the present invention more obvious and understandable, specific embodiments of the present invention are described below. Attached Figure Description

[0056] Various other advantages and benefits will become apparent to those skilled in the art upon reading the following detailed description of preferred embodiments. The accompanying drawings are for illustrative purposes only and are not intended to limit the invention. Furthermore, the same reference numerals denote the same parts throughout the drawings. In the drawings:

[0057] Figure 1 A schematic flowchart of the layered and segmented steam injection method for thermal recovery wells according to an embodiment of the present invention is shown;

[0058] Figure 2 A schematic diagram showing the distribution of near-wellbore physical properties in the target reservoir well according to an embodiment of the present invention is provided.

[0059] Figures 3a to 3c This diagram illustrates the temperature, pressure, and heat loss variations along the path of the horizontal section of the target reservoir well according to an embodiment of the present invention.

[0060] Figure 4 This invention presents a cloud map showing the temperature field development before and after steam injection predicted by CMG software for the target reservoir well in an embodiment of the present invention.

[0061] Figure 5 A schematic diagram of the structure of a stratified and segmented steam injection device for thermal recovery wells according to an embodiment of the present invention is shown. Detailed Implementation

[0062] Exemplary embodiments of the invention will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the invention are shown in the drawings, it should be understood that the invention may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this invention will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art.

[0063] Example 1:

[0064] Figure 1 A schematic flowchart of a layered and segmented steam injection method for thermal recovery wells according to an embodiment of the present invention is shown. Specifically, as... Figure 1 As shown, it includes the following steps:

[0065] Step S101: Obtain well data for the target well, including reservoir physical property distribution data, steam injection capacity data, and test data.

[0066] In this step, to achieve uniform utilization of different layers and expand the steam injection sweep range of heavy oil reservoirs, it is first necessary to collect data on the wells (target wells) where layered steam injection measures are implemented, clarifying the reservoir property distribution, steam injection capacity, and test data of the wells. The reservoir property distribution data reflects the heterogeneity and oil and gas distribution characteristics of the reservoir, including permeability, porosity, reservoir thickness, oil saturation, and formation crude oil viscosity of each layer. The steam injection capacity data reflects the recommended steam absorption capacity of the well, including wellhead pressure, wellhead temperature, wellhead steam dryness, steam injection flow rate, and total steam injection volume. Test data includes well trajectory data, casing and screen specifications and dimensions, layered packer installation locations, geothermal gradient, and annular medium type.

[0067] Step S102: Calculate the radius of the heating zone based on the well data, establish a segment injection ratio model based on the consistent heating zone radius, divide the segments according to the segment injection ratio model and calculate the fluid injection ratio of each segment.

[0068] First, aiming for a generally consistent formation heating range across the steam injection well sections, a reasonable heating zone radius is determined. Using this consistent heating radius as a standard, a layer-by-layer injection ratio model considering reservoir characteristics and steam injection capacity is established. Specifically, to determine the reasonable heating zone radius, a heating radius calculation model is used, as shown below:

[0069]

[0070] Dimensionless time specifically refers to:

[0071] Where, r h i is the radius of the heating zone, in meters; s The superheated steam injection rate is expressed in kg / s or h. m λ represents the enthalpy of saturated vapor, expressed in kJ / kg. s α represents the thermal conductivity of the top and bottom layers of rock, expressed in W / (m·℃); s The thermal diffusivity of the top and bottom layers is expressed in meters (m). 2 / h;M R This refers to the heat capacity of the oil reservoir, expressed in J / (m³). 3 ·℃); h is the oil layer thickness in m; ΔT is the temperature change in ℃; t is the steam injection time in h; erfc is the error complementarity function, erfc(x)=1-erf(x), erf(x) is the error function (also known as the Gaussian error function).

[0072] To further optimize the injection ratio between different layers, and considering the differences in reservoir characteristics and the influence of steam injection capacity in different layers, a layer injection ratio model is established based on the standard of consistent heating zone radius. The layer injection ratio model is shown below:

[0073]

[0074] Among them, I r R is the injection ratio for each layer; k For permeability gradients; R H For reservoir thickness gradients; R so R represents the residual oil saturation level difference. μo R represents the viscosity grade difference of crude oil. std This represents the porosity grade difference.

[0075] Then, based on the fluid distribution ratio model of this layer segment, the layer segment division is achieved using the inter-layer differential derivative discrimination principle, and the fluid distribution ratio of each segment is calculated. The differential derivative represents the change in the distribution ratio between the current small layer and the previous small layer. The larger the value, the greater the change in the required fluid distribution to ensure a consistent heating radius in this small layer, thus indicating a greater change in its physical properties. Since there are differences in physical properties (such as permeability, thickness, reservoir thickness, oil saturation, and formation crude oil viscosity) between different oil layers, the inter-layer differential derivative discrimination principle can be used to determine the degree of change in physical properties between adjacent layers to achieve layer segment division. Specifically, the inter-layer differential derivative model / formula is obtained by differentiating the flow distribution ratio model of the layer segment. Based on the fact that the inter-layer differential derivatives of adjacent segments reflect the degree of variation in physical properties, adjacent segments are distinguished or merged. Specifically, based on the comparison of the magnitudes of the inter-layer differential derivatives of adjacent segments, segments with larger differential derivatives are selected to be distinguished from the preceding segment. Adjacent segments with small changes in differential derivatives are identified as segments with similar physical properties and are then merged into new segments. This process is repeated to ultimately achieve the division or merging of adjacent segments. The physical property parameters of the newly merged segment are obtained through weighted averaging, and the differential of each physical property parameter in the new segment is calculated. Finally, the flow distribution ratio of each segment after division is calculated using the flow distribution ratio model of the layer segment. The inter-layer differential derivative model is obtained by differentiating the above-mentioned flow distribution ratio model. The model for the inter-layer differential derivative is as follows:

[0076]

[0077] Among them, the derivative of the interlayer level difference I r The meaning of ' is the change in the injection ratio between this sub-segment and the previous sub-segment. The larger the value, the greater the change in the injection amount required for this sub-segment to ensure the heating radius is consistent, which in turn indicates a greater change in its physical properties.

[0078] Step S103: Obtain the variation curve of fluid property parameters in the wellbore based on the variable mass two-phase flow heat transfer model in the wellbore.

[0079] When a fluid flows through a wellbore, it exchanges heat with the wellbore wall, causing changes in the fluid's physical properties. By inputting fluid parameters, flow conditions, and wellbore parameters into a variable-mass two-phase flow heat transfer model of the wellbore, the changes in the fluid's physical properties (curves) can be obtained. These curves describe the characteristics or patterns of how the fluid's physical properties change with the wellbore length. Analyzing the trends in these changes can reflect the heat transfer effect of the fluid within the wellbore.

[0080] In this step, the variation curves of wellbore fluid properties are obtained based on the variable-mass two-phase flow heat transfer model. Specifically, a variable-mass two-phase flow heat transfer model is established, considering the effects of steam dryness variation, orifice section fluid flow variation, and annular injection of non-condensable gas, including a constant-mass two-phase flow heat transfer model in the non-orifice section and a variable-mass two-phase flow heat transfer model in the orifice section. Both the constant-mass two-phase flow heat transfer model in the non-orifice section and the variable-mass two-phase flow heat transfer model in the orifice section further include mass conservation equations, momentum conservation equations, and energy conservation equations. Based on the fluid property parameter calculation model and the aforementioned variable-mass two-phase flow heat transfer model, the variation curves of wellbore fluid properties are obtained, including friction loss temperature variation, pressure variation, dryness variation, and heat transfer variation. By optimizing the fluid property parameter calculation model and the variable-mass two-phase flow heat transfer model, the variation curves of wellbore fluid properties can be obtained more accurately, thereby guiding the optimal configuration of the injection valve.

[0081] In this embodiment, the mass conservation equation is used to calculate the flow rate changes of the gas and liquid phases during the flow process. The optimized formula is shown below:

[0082]

[0083] Among them, G l G g These represent the liquid and gas mass flow rates within the wellbore, respectively; δm i It represents the total mass change of the gas-liquid two-phase fluid in the wellbore.

[0084] The momentum conservation equation is used to calculate the pressure drop along the wellbore during flow. The optimized formula is shown below:

[0085]

[0086] Where f is the two-phase flow friction coefficient, determined by manifold discrimination and calculation using the Beggs-Brill model; w is the flow velocity inside the pipe; and ρ is the gas-liquid two-phase density, ρ = xρ g +(1-x)ρl x represents steam dryness; ρ g ρ l denoted as gas phase density and liquid phase density, respectively; d is the inner diameter of the tubing; θ is the angle between the directional well section and the horizontal plane, with θ being 0 for the horizontal well section; g is the acceleration due to gravity.

[0087] The energy conservation equation is used to calculate the heat transfer along the wellbore and the changes in fluid temperature, dryness fraction, and enthalpy during two-phase flow. The optimized formula is shown below:

[0088]

[0089]

[0090]

[0091]

[0092] w g w l These represent the gas phase fluid velocity and the liquid phase fluid velocity, respectively; h g h l These are the enthalpy values ​​of the gas phase fluid and the liquid phase fluid, respectively; T in T represents the steam temperature inside the oil pipe. f Formation temperature; K d d is the heat transfer coefficient from the tubing to the formation; di d is the inner diameter of the oil pipe. do d is the outer diameter of the oil pipe. ci d is the inner diameter of the casing. co d is the outer diameter of the casing. h The outer diameter of the cement ring or screen tube; α di λ is the convective heat transfer coefficient between the steam and the inner wall of the oil pipe; p λ is the thermal conductivity of the oil pipe; b λ is the thermal conductivity of the sleeve; cem R is the thermal conductivity of the cement ring or screen tube. e and R f These are the annular thermal resistance and the formation thermal resistance, respectively.

[0093] Step S104: Determine the number of valve holes in each section based on the fluid injection volume and wellbore fluid property parameter variation curves, and arrange them evenly.

[0094] Given the injection valve orifice diameter, the required number of valve orifices for each section can be initially determined based on the fluid injection volume for each section. Since the physical properties of the wellbore fluid (such as pressure and density) also affect the setting of the number of valve orifices for each section, this step establishes a steam injection orifice flow rate calculation model based on the fluid injection volume for each section and the variation curves of the wellbore fluid physical properties. This model is used to determine the number of valve orifices for each section, further optimizing the valve orifice configuration.

[0095] Specifically, the fluid injection rate for each segment is obtained based on the fluid injection ratio for each segment, and the fluid pressure at the corresponding valve orifice is obtained based on the wellbore fluid property parameter variation curve. Assuming the formation pressure is the pressure outside the steam injection orifice and the pressure inside the steam injection orifice is the fluid pressure at the corresponding valve orifice location, the outlet velocity is obtained by calculating the pressure difference and fluid density on both sides of the steam injection orifice. Given the injection valve orifice diameter and designed injection rate, the required number of valve orifices for that segment is determined and evenly distributed. The injection rate is determined based on the fluid injection ratio for each segment.

[0096] In this step, an orifice flow velocity model is established using the pressure difference and fluid density across the steam injection orifice, as shown below:

[0097] c 2 =2(p2-p1) / ρ

[0098] Where c is the outlet velocity, p1 and p2 are the pressure differences on both sides of the steam injection hole, and ρ is the fluid density;

[0099] The relationship between the injection volume and the flow rate of each outlet is as follows:

[0100]

[0101] Where Q is the dispensing volume and n is the number of valve orifices, Q i Q represents the flow rate at each outlet. The flow rates at each outlet can be equal or unequal. i =πd 2 c / 4, where d is the orifice diameter of the dispensing valve. For example, assuming that the flow rate of each outlet is equal, that is, the valve orifice diameter of each outlet is the same, the number of valve orifices can be obtained by dividing the dispensing quantity by the flow rate of each outlet.

[0102] Step S105: According to the established steam injection plan for each layer, carry out steam injection construction operations for each layer.

[0103] Before carrying out steam injection operations at each stage, the development effect can be simulated or predicted based on the established steam injection plan, for example, using digital simulation software (such as CMG). Experiments show that the steam injection method provided in this embodiment, compared with general steam injection, expands the steam sweep range, suppresses steam / water channeling, and significantly improves the steam injection effect.

[0104] The solution provided in the above embodiments of the present invention obtains well data of the target well, including reservoir physical property distribution data, steam injection capacity data, and test data; calculates the heating zone radius based on the well data, establishes a layer-by-layer injection ratio model based on the uniformity of the heating zone radius, divides the well into layers according to the layer-by-layer injection ratio model, and calculates the fluid injection ratio of each layer; obtains the wellbore fluid physical property parameter variation curves based on the wellbore variable mass two-phase flow heat transfer model; determines the number of valve holes in each layer based on the fluid injection volume and wellbore fluid physical property parameter variation curves, and arranges them uniformly; and performs steam injection operations in each layer according to the established layer-by-layer steam injection plan. The present invention achieves uniform utilization of different layers, expands the steam injection sweep range of heavy oil reservoirs, and thus improves the reservoir utilization degree, well production, and recovery rate.

[0105] Example 2:

[0106] In this embodiment, a detailed explanation is given using well B6H in an offshore L oilfield as an example of a horizontal well implementing staged steam injection. Well B6H is located in the Guantao Formation of the western block of the L oilfield, belonging to a normal pressure and temperature system, with an original formation pressure of 15.3 MPa. Specifically, the following steps are included:

[0107] Step 1: Obtain well data for this well. The wellbore string parameters and formation heat transfer parameters are shown in Table 1, where the vertical well section is 1531m long and the horizontal well section is 205.4m long. The designed wellhead steam injection parameters are shown in Table 2, and the distribution of physical properties such as permeability, porosity, and horizontal section length in each near-wellbore layer is shown in Table 2. Figure 2 As shown.

[0108] Table 1: Wellbore string parameters and wellbore formation heat transfer parameters

[0109]

[0110] Table 2: Design Wellhead Steam Injection Parameters

[0111] Steam injection pressure, MPa 18 Steam injection flow rate, t / d 12.5 Wellhead steam dryness, % 85 Periodic steam injection volume, t 5440

[0112] Step 2: Divide the well into segments according to the segment injection ratio model and calculate the fluid injection ratio for each segment. Substitute the physical property parameters of each segment of the B6H well into the inter-segment differential derivative model / formula in Example 1 to obtain the data such as permeability, porosity, horizontal segment length, and differential derivative for each segment as shown in Table 3.

[0113] Table 3: Calculation results of the derivative of the inter-layer grade difference in well B6H

[0114]

[0115] By screening and comparing the segments with larger inter-layer differential derivatives, each sub-layer is divided into three segments with similar physical properties. The weighted average physical property distribution parameters of each segment are shown in Table 4.

[0116] Table 4: Weighted average physical property distribution parameters of the B6H well section

[0117] 1 1741.4 30.5 56 2 750.3 27.8 72.9 3 1966.4 31.1 76.5

[0118] The injection ratio and injection volume of each segment were quantitatively calculated using the inter-segment injection ratio model. The calculation results are shown in Table 5.

[0119] Table 5: Calculation Results of Segmented Injection

[0120] 1 33.3 4.163 2 34.46 4.307 3 32.24 4.03

[0121] Step 3: Obtain the wellbore fluid property parameter variation curves based on the variable mass two-phase flow heat transfer model. After establishing the variable mass two-phase flow heat transfer model based on the B6H wellbore, input the design wellhead steam injection parameters provided in Table 2 into the model to calculate the steam parameters at the horizontal section heel: pressure 16.47 MPa, temperature 349.7℃, steam dryness fraction 0.4. The following formula is then compiled... Figures 3a to 3c The curves showing the changes in temperature, pressure, and heat loss along the path are shown.

[0122] Step four: Determine the number of valve orifices for each section based on the fluid injection volume and wellbore fluid property parameter variation curves. Using injection valves of the same injection orifice diameter, each valve can carry a maximum of four 10mm injection orifices. Substitute the calculated section injection volume and wellbore horizontal section steam property parameters into the injection orifice flow calculation model to obtain the number of injection orifices for each section. Specifically, section 1 has 10 injection orifices and 3 injection valves; section 2 has 14 injection orifices and 4 injection valves; section 3 has 16 injection orifices and 4 injection valves. Detailed calculation results are shown in Table 6.

[0123] Table 6: Calculation Results of the Number of Valve Holes in Each Section

[0124] 1 0-56m 10 3 One 4*Φ10mm, two 3*Φ10mm 2 56-128.9m 14 4 Two 4*Φ10mm, two 3*Φ10mm 3 128.9-205.4m 16 4 4 x 4*Φ10mm

[0125] Step 5: Simulate or predict the development effect based on the established steam injection plan for each layer. Before carrying out steam injection operations for each layer, based on the calculated steam injection volume and determined steam injection method for each layer, simulate or predict the development effect using digital simulation software (such as CMG). The temperature field development cloud map is shown below. Figure 4 As shown, compared with general steam injection, segmented steam injection resulted in a more uniform temperature field development, effectively adjusted the steam absorption profile of the horizontal well section, increased the overall operational length of the reservoir in the horizontal well section by 60% to 70%, and increased the cumulative oil production by 1251.6 cubic meters per cycle, demonstrating significant development effects.

[0126] The solution provided in the above embodiments of the present invention obtains well data of the target well, including reservoir physical property distribution data, steam injection capacity data, and test data; calculates the heating zone radius based on the well data, establishes a layer-by-layer injection ratio model based on the uniformity of the heating zone radius, divides the well into layers according to the layer-by-layer injection ratio model, and calculates the fluid injection ratio of each layer; obtains the wellbore fluid physical property parameter variation curves based on the wellbore variable mass two-phase flow heat transfer model; determines the number of valve holes in each layer based on the fluid injection volume and wellbore fluid physical property parameter variation curves, and arranges them uniformly; and performs steam injection operations in each layer according to the established layer-by-layer steam injection plan. The present invention achieves uniform utilization of different layers, expands the steam injection sweep range of heavy oil reservoirs, and thus improves the reservoir utilization degree, well production, and recovery rate.

[0127] Example 3:

[0128] Figure 5 A schematic diagram of the structure of a stratified steam injection device for thermal recovery wells according to an embodiment of the present invention is shown. The stratified steam injection device 500 for thermal recovery wells includes: a well data acquisition module 510, an injection ratio calculation module 520, a physical property parameter calculation module 530, and a valve orifice number calculation module 540.

[0129] The well data acquisition module 510 is used to acquire well data of the target well, including reservoir physical property distribution data, steam injection capacity data, and test data.

[0130] The injection ratio calculation module 520 is used to calculate the radius of the heating zone based on the well data, establish a segment injection ratio model based on the consistency of the heating zone radius, divide the segments according to the segment injection ratio model, and calculate the fluid injection ratio of each segment.

[0131] The physical property parameter calculation module 530 is used to obtain the variation curve of the physical property parameters of the well fluid according to the variable mass two-phase flow heat transfer model of the well.

[0132] The valve hole quantity calculation module 540 is used to determine the number of valve holes in each section based on the fluid injection volume and well fluid property parameter variation curves of each section, and to arrange them evenly so as to carry out steam injection construction operations in each section according to the established steam injection plan.

[0133] In an alternative embodiment, the dispensing ratio calculation module 520 is further configured to:

[0134] The derivative of the inter-layer grade difference is obtained by differentiating the grade distribution ratio model.

[0135] Based on the comparison of the magnitude of the derivative of the inter-layer difference between adjacent layers, adjacent layers are distinguished or merged.

[0136] The fluid distribution ratio of each segment is obtained through the segment distribution ratio model.

[0137] In an alternative embodiment, the dispensing ratio calculation module 520 is further configured to:

[0138] Based on the established layer-by-layer injection ratio model, the layer division is achieved using the inter-layer differential derivative discrimination principle. The differential derivative represents the change in the injection ratio between the current layer and the previous layer. The larger the value, the greater the change in the injection amount required for the current layer to ensure consistent heating radius, which in turn indicates a greater change in its physical properties.

[0139] Based on the obtained reservoir physical property distribution data, calculate the permeability difference, porosity difference, reservoir thickness difference, oil saturation difference, and formation crude oil viscosity difference of each layer.

[0140] The derivative of each segment is calculated using the formula for the derivative of the inter-segment difference. By comparing the magnitudes of the derivatives of the inter-segment differences between adjacent segments, adjacent segments are distinguished or merged.

[0141] In an alternative embodiment, the dispensing ratio calculation module 520 is further configured to:

[0142] The physical property parameters of the newly merged segments are obtained by weighted averaging, the difference in the physical property parameters of each segment is calculated, and the fluid allocation ratio of each segment after division is calculated by the segment allocation ratio model.

[0143] In one alternative approach, the reservoir property distribution data includes one or more of the following: permeability, porosity, reservoir thickness, oil saturation, and formation crude oil viscosity for each segment.

[0144] The steam injection capacity data includes one or more of the following: wellhead pressure, wellhead temperature, wellhead steam dryness, steam injection flow rate, and total steam injection volume;

[0145] The test data includes one or more of the following: well trajectory data, casing and screen specifications and dimensions, installation location of layered and segmented packers, geothermal gradient, and annular medium type.

[0146] In an alternative embodiment, the physical property parameter calculation module 530 is further configured to:

[0147] A variable mass two-phase flow heat transfer model for wellbore is established, which considers the changes in steam dryness, the changes in fluid flow rate in the orifice section, and the influence of non-condensate gas injection in the annulus. The model includes a constant mass two-phase flow heat transfer model in the non-orifice section and a variable mass two-phase flow heat transfer model in the orifice section.

[0148] In one optional embodiment, the constant mass two-phase flow heat transfer model in the non-aperture section and the variable mass two-phase flow heat transfer model in the aperture section further include the mass conservation equation, the momentum conservation equation, and the energy conservation equation.

[0149] The mass conservation equation is used to calculate the flow rate changes of the gas and liquid phases during a flow process. The optimized formula is shown below:

[0150]

[0151] Among them, G l G g These represent the liquid and gaseous mass flow rates within the wellbore, respectively; δm i This represents the total mass change of the gas-liquid two-phase fluid in the wellbore;

[0152] The momentum conservation equation is used to calculate the pressure drop along the wellbore during flow. The optimized formula is shown below:

[0153]

[0154] Where f is the two-phase flow friction coefficient, determined by manifold discrimination and calculation using the Beggs-Brill model; w is the flow velocity inside the pipe; and ρ is the gas-liquid two-phase density, ρ = xρ g +(1-x)ρ l x represents steam dryness; ρ g ρ l These represent the gas phase density and liquid phase density, respectively; d is the inner diameter of the tubing; θ is the angle between the directional well section and the horizontal plane, with 0 for the horizontal section; g is the acceleration due to gravity.

[0155] The energy conservation equation is used to calculate the heat transfer along the wellbore and the changes in fluid temperature, dryness fraction, and enthalpy during two-phase flow. The optimized formula is shown below:

[0156]

[0157]

[0158]

[0159]

[0160] w g w l These represent the gas phase fluid velocity and the liquid phase fluid velocity, respectively; h g h l These are the enthalpy values ​​of the gas phase fluid and the liquid phase fluid, respectively; T in T represents the steam temperature inside the oil pipe. f Formation temperature; K d d is the heat transfer coefficient from the tubing to the formation;di d is the inner diameter of the oil pipe. do d is the outer diameter of the oil pipe. ci d is the inner diameter of the casing. co d is the outer diameter of the casing. h The outer diameter of the cement ring or screen tube; α di λ is the convective heat transfer coefficient between the steam and the inner wall of the oil pipe; p λ is the thermal conductivity of the oil pipe; b λ is the thermal conductivity of the sleeve; cem R is the thermal conductivity of the cement ring or screen tube. e and R f These are the annular thermal resistance and the formation thermal resistance, respectively.

[0161] In an alternative embodiment, the physical property parameter calculation module 530 is further configured to:

[0162] Based on the fluid property parameter calculation model and the wellbore variable mass two-phase flow heat transfer model, the variation curve of the fluid property parameters in the wellbore is obtained.

[0163] In an alternative embodiment, the physical property parameter calculation module 530 is further configured to:

[0164] A variable-mass two-phase flow heat transfer model is established in the wellbore. This model considers variations in steam dryness, fluid flow rate variations in the orifice section, and the influence of non-condensable gas injection into the annulus. It includes a constant-mass two-phase flow heat transfer model for the non-orifice section and a variable-mass two-phase flow model for the orifice section. The two-phase flow heat transfer model further includes mass conservation equations, momentum conservation equations, and energy conservation equations.

[0165] Based on the fluid property parameter calculation model and the wellbore variable mass two-phase flow model, the variation curve of the fluid property parameters in the wellbore is obtained.

[0166] In an alternative embodiment, the valve orifice number calculation module 540 is further configured to:

[0167] The pressure difference between the two sides of the steam injection hole is obtained based on the change curve of the fluid properties in the wellbore.

[0168] The outlet flow velocity is obtained based on the pressure difference and fluid density on both sides of the steam injection port. The number of valve ports required for each layer is determined based on the preset injection valve orifice diameter and injection volume. The injection volume is determined based on the fluid injection ratio of each layer.

[0169] In one alternative approach, the model for the outlet flow velocity is:

[0170] c 2 =2(p2-p1) / ρ

[0171] Where c is the outlet velocity, p1 and p2 are the pressure differences on both sides of the steam injection hole, and ρ is the fluid density.

[0172] The relationship between the injection volume and the flow rate of each outlet is as follows:

[0173]

[0174] Where Q is the dispensing volume and n is the number of valve orifices, Q i Q represents the flow rate at each outlet. i =πd 2 c / 4, where d is the orifice diameter of the dispensing valve.

[0175] The solution provided in the above embodiments of the present invention obtains well data of the target well, including reservoir physical property distribution data, steam injection capacity data, and test data; calculates the heating zone radius based on the well data, establishes a layer-by-layer injection ratio model based on the uniformity of the heating zone radius, divides the well into layers according to the layer-by-layer injection ratio model, and calculates the fluid injection ratio of each layer; obtains the wellbore fluid physical property parameter variation curves based on the wellbore variable mass two-phase flow heat transfer model; determines the number of valve holes in each layer based on the fluid injection volume and wellbore fluid physical property parameter variation curves, and arranges them uniformly; and performs steam injection operations in each layer according to the established layer-by-layer steam injection plan. The present invention achieves uniform utilization of different layers, expands the steam injection sweep range of heavy oil reservoirs, and thus improves the reservoir utilization degree, well production, and recovery rate.

[0176] The algorithms or displays provided herein are not inherently related to any particular computer, virtual system, or other device. Various general-purpose systems can also be used in conjunction with the teachings herein. The required structure for constructing such systems is apparent from the above description. Furthermore, the embodiments of the present invention are not directed to any particular programming language. It should be understood that the content of the invention described herein can be implemented using various programming languages, and the above description of specific languages ​​is for the purpose of disclosing the best mode of implementation of the invention.

[0177] Numerous specific details are set forth in the specification provided herein. However, it will be understood that embodiments of the invention may be practiced without these specific details. In some instances, well-known methods, structures, and techniques have not been shown in detail so as not to obscure the understanding of this specification.

[0178] Similarly, it should be understood that, in order to simplify the invention and aid in understanding one or more of the various inventive aspects, features of the embodiments of the invention are sometimes grouped together in a single embodiment, figure, or description thereof in the above description of exemplary embodiments of the invention. However, this disclosure should not be construed as reflecting an intention that the claimed invention requires more features than are expressly recited in each claim. Rather, as reflected in the following claims, inventive aspects lie in fewer than all features of a single foregoing disclosed embodiment. Therefore, the claims following the detailed description are hereby expressly incorporated into this detailed description, wherein each claim itself is a separate embodiment of the invention.

[0179] Those skilled in the art will understand that modules in the device of the embodiments can be adaptively changed and placed in one or more devices different from that embodiment. Modules, units, or components in the embodiments can be combined into a single module, unit, or component, and further, they can be divided into multiple sub-modules, sub-units, or sub-components. Except where at least some of such features and / or processes or units are mutually exclusive, any combination can be used to combine all features disclosed in this specification (including the accompanying claims, abstract, and drawings) and all processes or units of any method or device so disclosed. Unless expressly stated otherwise, each feature disclosed in this specification (including the accompanying claims, abstract, and drawings) may be replaced by an alternative feature that serves the same, equivalent, or similar purpose.

[0180] Furthermore, those skilled in the art will understand that although some embodiments herein include certain features included in other embodiments but not others, combinations of features from different embodiments are intended to be within the scope of the invention and form different embodiments. For example, in the following claims, any of the claimed embodiments can be used in any combination.

[0181] The various component embodiments of the present invention can be implemented in hardware, or as software modules running on one or more processors, or a combination thereof. Those skilled in the art will understand that microprocessors or digital signal processors (DSPs) can be used in practice to implement some or all of the functions of some or all of the components according to the embodiments of the present invention. The present invention can also be implemented as a device or apparatus program (e.g., a computer program and computer program product) for performing part or all of the methods described herein. Such programs implementing the present invention can be stored on a computer-readable medium, or can be in the form of one or more signals. Such signals can be downloaded from an Internet website, provided on a carrier signal, or provided in any other form.

[0182] It should be noted that the above embodiments are illustrative of the invention and not restrictive, and that those skilled in the art can devise alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses should not be construed as limiting the claims. The word "comprising" does not exclude the presence of elements or steps not listed in the claims. The word "a" or "an" preceding an element does not exclude the presence of a plurality of such elements. The invention can be implemented by means of hardware comprising several different elements and by means of a suitably programmed computer. In the unit claims enumerating several means, several of these means may be embodied by the same item of hardware. The use of the words first, second, and third, etc., does not indicate any order. These words can be interpreted as names. The steps in the above embodiments, unless otherwise specified, should not be construed as limiting the order of execution.

Claims

1. A method for layered and segmented steam injection in thermal recovery wells, characterized in that, include: Step 1: Obtain well data for the target well, including reservoir physical property distribution data, steam injection capacity data, and test data; Step 2: Calculate the radius of the heating zone based on the well data. Establish a segmented injection ratio model based on the consistent radius of the heating zone. Divide the layers according to the segmented injection ratio model and calculate the fluid injection ratio for each layer. Specifically, differentiate the segmented injection ratio model to obtain the inter-layer differential derivative. Based on the comparison of the magnitude of the inter-layer differential derivatives of adjacent layers, distinguish or merge adjacent layers. Obtain the fluid injection ratio for each divided layer using the segmented injection ratio model. The segmental injection ratio model is as follows: in, I r The ratio of injection points to layers; R k This represents the permeability gradient; R H This represents the thickness difference of the oil reservoir. R so This represents the difference in remaining oil saturation levels; R μo This represents the viscosity grade difference of crude oil; R std Porosity grade difference; The calculation model for the radius of the heating zone is as follows: Dimensionless time is specifically: in, r h The radius of the heating zone is in meters. i s This is the superheated steam injection rate, expressed in kg / s. h m This is the enthalpy of saturated vapor, expressed in kJ / kg. λ s The thermal conductivity of the top and bottom layers of rock is expressed in W / (m·℃). α s The thermal diffusivity of the top and bottom layers is expressed in m. 2 / h; M R This refers to the heat capacity of the oil reservoir, expressed in J / (m³). 3 ·℃); h The oil layer thickness is expressed in meters (m); Δ T This represents the temperature change, expressed in °C. t This refers to the steam injection time, expressed in hours (h). erfc It is an error complementarity function. erfc (x)=1- erf (x), erf (x) is the error function; Step 3: Obtain the variation curves of fluid properties in the wellbore based on the variable mass two-phase flow heat transfer model in the wellbore; Step 4: Determine the number of valve holes in each section based on the fluid injection volume and wellbore fluid property parameter variation curves, and arrange them evenly. Step 5: Carry out steam injection operations for each layer according to the established layer steam injection plan.

2. The method according to claim 1, characterized in that, The step of dividing the layers according to the layer allocation ratio model further includes: Based on the established layer-by-layer injection ratio model, the layer division is achieved using the interlayer differential derivative discrimination principle. The meaning of the interlayer differential derivative is the change in the injection ratio between the current layer and the previous layer. The larger the value, the greater the change in the injection amount required for the current layer to ensure consistent heating radius, and thus the greater the change in its physical properties. Based on the obtained reservoir physical property distribution data, calculate the permeability difference, porosity difference, reservoir thickness difference, oil saturation difference, and formation crude oil viscosity difference of each layer. The derivative of each segment is calculated using the formula for the derivative of the inter-segment difference. By comparing the magnitudes of the derivatives of the inter-segment differences between adjacent segments, adjacent segments are distinguished or merged.

3. The method according to claim 1, characterized in that, The fluid allocation ratio of each segment obtained through the segment allocation ratio model further includes: The physical property parameters of the newly merged segments are obtained by weighted averaging, the difference in the physical property parameters of each segment is calculated, and the fluid allocation ratio of each segment after division is calculated by the segment allocation ratio model.

4. The method according to claim 1, characterized in that, The reservoir physical property distribution data includes one or more of the following: permeability, porosity, reservoir thickness, oil saturation, and formation crude oil viscosity of each layer. The steam injection capacity data includes one or more of the following: wellhead pressure, wellhead temperature, wellhead steam dryness, steam injection flow rate, and total steam injection volume; The test data includes one or more of the following: well trajectory data, casing and screen specifications and dimensions, installation location of layered and segmented packers, geothermal gradient, and annular medium type.

5. The method according to any one of claims 1-4, characterized in that, The step of obtaining the wellbore fluid property parameter variation curves based on the wellbore variable mass two-phase flow heat transfer model further includes: A variable mass two-phase flow heat transfer model for wellbore is established, which considers the changes in steam dryness, the changes in fluid flow rate in the orifice section, and the influence of non-condensate gas injection in the annulus. The model includes a constant mass two-phase flow heat transfer model in the non-orifice section and a variable mass two-phase flow heat transfer model in the orifice section.

6. The method according to claim 5, characterized in that, The constant-mass two-phase flow heat transfer model in the non-aperture section and the variable-mass two-phase flow heat transfer model in the aperture section further include: mass conservation equation, momentum conservation equation and energy conservation equation. The mass conservation equation is used to calculate the flow rate changes of the gas and liquid phases during a flow process. The optimized formula is shown below: in, G l , G g These are the mass flow rates of the liquid and gas phases within the wellbore, respectively. δm i This represents the total mass change of the gas-liquid two-phase fluid in the wellbore; The momentum conservation equation is used to calculate the pressure drop along the wellbore during flow. The optimized formula is shown below: in, f The friction coefficient for two-phase flow is determined by manifold discrimination and calculation using the Beggs-Brill model. w The flow velocity inside the pipe; ρ The density of the gas-liquid two phases is... ; x Steam dryness; ρ g , ρ l These are the gas phase density and the liquid phase density, respectively. d This refers to the inner diameter of the oil pipe. θ θ is the angle between the directional well section and the horizontal plane, with θ being 0 for the horizontal well section; g is the acceleration due to gravity. The energy conservation equation is used to calculate the heat transfer along the wellbore and the changes in fluid temperature, dryness fraction, and enthalpy during two-phase flow. The optimized formula is shown below: w g , w l These are the gas phase fluid velocity and the liquid phase fluid velocity, respectively. h g , h l These are the enthalpy values ​​of the gas phase fluid and the liquid phase fluid, respectively. T in This refers to the steam temperature inside the oil pipe. T f Formation temperature; K d The heat transfer coefficient from the tubing to the formation; d di This refers to the inner diameter of the oil pipe. d do The outer diameter of the oil pipe; d ci The inner diameter of the casing; d co The outer diameter of the casing; d h The outer diameter of the cement ring or screen tube; α di The convective heat transfer coefficient between the steam and the inner wall of the oil pipe; The thermal conductivity of the oil pipe; The thermal conductivity of the sleeve; λ cem The thermal conductivity of the cement ring or screen tube; R e and R f These are the annular thermal resistance and the formation thermal resistance, respectively. The step of obtaining the wellbore fluid property parameter variation curve based on the wellbore variable mass two-phase flow heat transfer model further includes: obtaining the wellbore fluid property parameter variation curve based on the fluid property parameter calculation model and the wellbore variable mass two-phase flow heat transfer model.

7. The method according to claim 1, characterized in that, The step of determining the number of valve holes in each section and arranging them evenly based on the fluid injection volume and wellbore fluid property parameter variation curves of each section further includes: The pressure difference between the two sides of the steam injection hole is obtained based on the change curve of the fluid properties in the wellbore. The outlet flow velocity is obtained based on the pressure difference and fluid density on both sides of the steam injection port. The number of valve ports required for each layer is determined based on the preset injection valve orifice diameter and injection volume. The injection volume is determined according to the fluid injection ratio of each layer.

8. The method according to claim 7, characterized in that, The model for the outlet flow velocity is: in, c The outflow velocity is the velocity at the outlet. p 1, p 2 represents the pressure difference between the two sides of the steam injection port. ρ For fluid density; The relationship between the injection volume and the flow rate of each outlet is as follows: in, Q For the amount to be dispensed, n For the number of valve holes, Q i For the flow rate of each outlet, , d This refers to the orifice diameter of the injection valve.

9. A stratified and segmented steam injection device for thermal recovery wells, characterized in that, include: The well data acquisition module is used to acquire well data of the target well, including reservoir physical property distribution data, steam injection capacity data, and test data. The fluid injection ratio calculation module is used to calculate the radius of the heating zone based on the well data, establish a segment fluid injection ratio model with the heating zone radius being consistent as a standard, divide the layers according to the segment fluid injection ratio model, and calculate the fluid injection ratio of each layer; wherein, the derivative of the segment fluid injection ratio model is obtained by taking the derivative of the inter-layer difference; based on the comparison of the magnitude of the inter-layer difference derivative of adjacent layers, adjacent layers are distinguished or merged; and the fluid injection ratio of each divided layer is obtained through the segment fluid injection ratio model. The segmental injection ratio model is as follows: in, I r The ratio of injection points to layers; R k This represents the permeability gradient; R H This represents the thickness difference of the oil reservoir. R so This represents the difference in remaining oil saturation levels; R μo This represents the viscosity grade difference of crude oil; R std Porosity grade difference; The calculation model for the radius of the heating zone is as follows: Dimensionless time is specifically: in, r h The radius of the heating zone is in meters. i s This is the superheated steam injection rate, expressed in kg / s. h m This is the enthalpy of saturated vapor, expressed in kJ / kg. λ s The thermal conductivity of the top and bottom layers of rock is expressed in W / (m·℃). α s The thermal diffusivity of the top and bottom layers is expressed in m. 2 / h; M R This refers to the heat capacity of the oil reservoir, expressed in J / (m³). 3 ·℃); h The oil layer thickness is expressed in meters (m); Δ T This represents the temperature change, expressed in °C. t This refers to the steam injection time, expressed in hours (h). erfc It is an error complementarity function. erfc (x)=1- erf (x), erf (x) is the error function; The physical property parameter calculation module is used to obtain the variation curves of the physical property parameters of the well fluid based on the variable mass two-phase flow heat transfer model of the wellbore. The valve orifice quantity calculation module is used to determine the number of valve orifices in each section based on the fluid injection volume and wellbore fluid property parameter variation curves, and to evenly distribute them so as to carry out steam injection construction operations in each section according to the established steam injection plan.

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