A method for establishing and applying wellhead temperature prediction charts

Abstract

This invention discloses a method for establishing a wellhead temperature prediction chart and its application, belonging to the field of oil and gas extraction technology. Its key features include: dividing the wellbore into two parts based on the well structure; coupling the steady-state field within the wellbore with the unsteady field of the formation to calculate the wellbore temperature field; forming different combinations of insulation and anti-corrosion layers based on different tubing lining materials; calculating the temperature of heavy oil reaching the wellhead under different lining materials to determine the lining material with the best insulation effect; and establishing a wellhead temperature prediction chart under the influence of the tubing running depth and daily production rate, and calculating the boundary curve equation of the tubing running depth and daily production rate under the minimum wellhead temperature requirement, providing a technical basis for optimizing heavy oil extraction parameters.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas extraction technology, specifically relating to a method for establishing and applying wellhead temperature prediction charts. Background Technology

[0002] Due to the high viscosity and high wax content of heavy oil at room temperature, its flowability is poor. On-site auxiliary heating and other methods are required to achieve continuous extraction. At the same time, it is impossible to avoid the input and waste of other resources. However, how to reduce costs and increase efficiency is still a challenge for heavy oil extraction technology (Jiang Qi, You Hongjuan, Pan Jingjun, et al. Preliminary discussion on the current status and development direction of heavy oil extraction technology [J]. Special Oil and Gas Reservoirs, 2020, 27(06):30-39).

[0003] According to field data from oilfields, the viscosity of oil produced from heavy oil wells is generally very high, which greatly increases the cost of investing in surface auxiliary equipment. Currently, scholars have established a temperature field model for the wellbore of heavy oil wells (Zhu Guanghai, Liu Zhangcong, Xiong Xudong, et al. Numerical calculation method for temperature field of electrically heated heavy oil wellbore [J]. Petroleum Drilling Technology, 2019, 47(05): 110-115). However, due to the simple manufacturing process and low cost of insulated tubing, it has been widely used in the field, and beneficial results have also been achieved in the study of the performance of insulated lining materials. While studying the insulation performance of tubing, its corrosion resistance is often neglected. Therefore, based on the use of insulated tubing with both insulation and anti-corrosion layers, it is crucial to establish a method for predicting the wellhead temperature of heavy oil wells using insulated tubing with insulated lining, providing a basis for the selection of insulated tubing lining materials and the optimization of mining parameters in the field. Summary of the Invention

[0004] To address the shortcomings of existing technologies, this invention provides a method and application for establishing a wellhead temperature prediction chart. It establishes a mathematical model of the wellbore temperature field and draws a wellhead temperature prediction chart under the condition of heavy oil well lining insulated tubing, providing support for the optimization design of oil and gas field production parameters.

[0005] The technical problem solved by this invention is addressed by the following technical solution: a method for establishing and applying a wellhead temperature prediction chart, comprising the following steps:

[0006] Step 1: Calculate the heat transfer flow rate of each layer of the wellbore; the wellbore is divided into two parts along its axial direction, and the well structure is as follows: Figure 2 As shown, the first part, from the inside out, consists of: layer 1 being heavy oil fluid, layer 2 being a tubing anti-corrosion layer, layer 3 being a tubing insulation layer, layer 4 being a tubing anti-corrosion layer, layer 5 being the tubing itself, layer 6 being annular mixed with light oil, layer 7 being the oil layer casing, and layer 8 being a cement ring; the second part adds a 9th layer of technical casing and a 10th layer of cement ring compared to the first part; among them, layer 2 (tubing anti-corrosion layer), layer 3 (tubing insulation layer), and layer 4 (tubing anti-corrosion layer) constitute the tubing liner;

[0007] ① Layers 2, 3, 4, 5, 7, 8, 9, and 10 are solid layers, with radial heat flow Φ Si As in equation (1);

[0008]

[0009] Where: Φ Si Let W be the radial heat flux of the i-th layer; T be the heat flux of the i-th layer. 1i T represents the temperature of the inner wall of the i-th layer, in °C. 2i r is the temperature of the outer wall of the i-th layer, in °C; 1i Let r be the inner radius of the i-th layer, m; 2i Let λ be the outer radius of the i-th layer, m; i ΔL is the thermal conductivity of the i-th layer, W / (m·℃); ΔL is the unit length, m;

[0010] ② The heat flow rate Φ of convective heat transfer between the first layer of heavy oil fluid and the second layer of oil pipe anti-corrosion layer S1 As in equation (2);

[0011] Φ S1 =2πr 12 h1(T1-T 12 )ΔL(1)

[0012] Where: Φ S1 h1 is the heat flow rate of the convective heat transfer between the first layer of heavy oil fluid and the second layer of oil pipe corrosion protection layer, in W; h1 is the convective heat transfer coefficient between the first layer of heavy oil fluid and the second layer of oil pipe corrosion protection layer, in W / (m²). 2 ·℃); T1 is the temperature of the first layer of heavy oil fluid, ℃; T 12 The temperature of the inner wall of the second layer of the oil pipe corrosion protection layer is ℃; r 12 The inner radius of the second layer is m;

[0013] ③ The heat flow rate Φ of the convective heat transfer between the 6th layer annulus with diluted oil and the 5th layer oil pipe and the 7th layer oil casing S6 As in equation (3);

[0014] Φ S6 =2πr 25 h6(T 25 -T 17 )ΔL(3)

[0015] Where: Φ S6 h6 is the heat flow rate of convective heat transfer between the 6th layer annular layer diluted oil and the 5th layer oil pipe and the 7th layer oil casing, in W; h6 is the convective heat transfer coefficient between the 6th layer annular layer diluted oil and the 5th layer oil pipe and the 7th layer oil casing, in W / (m2). 2 ·℃); T 25 Temperature of the outer wall of the fifth oil pipe, in °C; T 17The temperature of the inner wall of the casing in the 7th oil layer is ℃; r 25 The outer radius of the 5th layer of tubing, in meters;

[0016] Step 2: Calculate the overall heat transfer coefficient of the wellbore.

[0017] Heat flow rate Φ of radial heat conduction in wellbore S As in equation (4);

[0018]

[0019] Where: Φ S Radial heat flow rate of the wellbore, W; The outer radius of the j-th section of the wellbore, in meters; k j Let J be the overall heat transfer coefficient for the j-th part, W / (m²). 2 ·℃); Let J be the temperature of the outer wall of the j-th section of the wellbore, in °C.

[0020] Substitute the heat flow of each layer from the 1st to the 10th layer obtained from ①②③ in step 1 and equation (4) into equation (5);

[0021] Φ S =Φ S1 =Φ S6 =Φ Si (i=2,3,4,5,7,8,9,10)(5)

[0022] The temperature difference T1-T2 between the first layer of heavy oil fluid in the first part of the wellbore and the outer wall temperature of the eighth layer is obtained according to equation (5). 1 As in equation (6);

[0023]

[0024] In the formula: T2 1 The temperature of the outer wall of the first section of the wellbore is in °C; r 12 r 22 These are the inner and outer radii of the second layer, respectively, in meters (m) and r. 13 r 23 These are the inner and outer radii of the 3rd layer, respectively, in meters (m) and r. 14 r 24 These are the inner and outer radii of the 4th layer, respectively, in meters (m); r 15 r 25 These are the inner and outer radii of the 5th layer, respectively, in meters (m); r 16 r 26 These are the inner and outer radii of the 6th layer annulus with diluted oil, respectively, in meters (m); r 17 r 27 These are the inner and outer radii of the 7th layer, respectively, in meters (m); r 18 r 28λ1, λ2, λ3, λ4, λ5, λ7, and λ8 are the inner and outer radii of the 8th layer, respectively, in meters; λ2, λ3, λ4, λ5, λ7, and λ8 are the thermal conductivity of the media in the 2nd, 3rd, 4th, 5th, 7th, and 8th layers, respectively, in W / (m·℃).

[0025] Combining equations (5) and (6), we obtain the first part of the radial total heat transfer coefficient k1 as shown in equation (7);

[0026]

[0027] According to equation (5), the temperature differences T1-T2 on the outer side of the first to tenth layers of the second part of the wellbore are obtained respectively. 2 As in equation (8);

[0028]

[0029] In the formula: Temperature outside the second section of the wellbore, in °C; r 19 r 29 These are the inner and outer radii of the 9th layer, respectively, in meters (m); r 110 r 210 These are the inner and outer radii of the 10th layer, respectively, in meters; λ9, λ 10 The values ​​are the thermal conductivity of the 9th and 10th layers, respectively, in W / (m·℃).

[0030] Combining equations (5) and (8), we obtain the second part of the radial total heat transfer coefficient k2 as shown in equation (9);

[0031]

[0032] Step 3: Calculate the temperature field in the wellbore.

[0033] In the first and second wellbore sections, the radial heat transfer Q1 from the fluid to the outer surface of the cement sheath is as shown in equation (10);

[0034]

[0035] In the formula: Q1 is the radial heat transfer within the wellbore, in W; Let k be the outer radius of the j-th section of the wellbore, in meters. lj T1 is the overall heat transfer coefficient of the j-th part, W / (m·℃); T1 is the temperature of the first layer of heavy oil fluid, ℃; dj represents the outer surface temperature of the j-th section of the wellbore, in °C; dz represents the length of the fluid micro-element inside the tubing.

[0036] The radial heat transfer from the outer surface of the wellbore to the formation is Q2 as shown in equation (11);

[0037]

[0038] in:

[0039]

[0040] In the formula: Q2 is the radial heat transfer from the wellbore exterior to the formation, W; T3 is the formation temperature, °C; α is the formation thermal diffusivity, dimensionless; t is the production time, h; λ e is the thermal conductivity of the formation, W / (m·℃);

[0041] The heat transferred from the wellbore to the outer surface of the cement is equal to the heat transferred from the outer surface of the cement to the surrounding strata, i.e., Q1 = Q2. Thus, by combining equations (10) and (11), we obtain equation (13).

[0042]

[0043] in:

[0044]

[0045] T3 = T w -g T z(15)

[0046] In the formula: C pm σ represents the isobaric specific heat of the well fluid, J / (kg·℃); o represents the daily fluid production, t / d; g T The geothermal gradient is expressed in °C / m and T. w Z represents the formation temperature at the bottom of the well, in °C; Z represents the depth, in meters.

[0047] At the bottom of the well, z = 0, T1 = T3 = T w The temperature T1 of any cross section of the heavy oil fluid in the tubing is obtained as shown in equation (16);

[0048]

[0049] Furthermore, the outer radius of the first part of the well shaft is the outer radius of the 8th layer of cement ring, and the outer radius of the second part of the well shaft is the outer radius of the 10th layer of cement ring;

[0050] Step 4: Select the tubing lining material and determine the thermal conductivity. The tubing lining material includes the tubing anti-corrosion layer material and the tubing insulation layer material. ① There is only one type of tubing anti-corrosion layer material and only one type of tubing insulation layer material provided on site. Then determine the thermal conductivity of the tubing anti-corrosion layer material and the tubing insulation layer material and proceed to step 5. ② There are multiple choices of tubing anti-corrosion layer material or tubing insulation layer material provided on site. The tubing anti-corrosion layer material and the tubing insulation layer material can be combined in pairs to form multiple schemes. After determining the thermal conductivity, calculate the different schemes according to formulas (1) to (16) when the daily fluid production is 80t / d, the insulation tubing is lowered to a depth of 3000m, and the bottom temperature is 100℃. Plot the curve of the change of heavy oil fluid temperature with depth under different schemes and obtain the wellhead temperature. The scheme with the highest temperature when the fluid reaches the wellhead is the optimal scheme. The corresponding tubing anti-corrosion layer material and the tubing insulation layer material are the optimal tubing lining materials. After selecting the optimal tubing lining material, proceed to step 5.

[0051] Step 5: Establish a wellhead temperature prediction chart, taking the daily production volume o and the depth of the insulated tubing h as influencing factors, and calculate the wellhead temperature according to formula (16); where the daily production volume o increases from 50t / d at intervals of at / d to 100t / d, and the depth of the insulated tubing h increases from 2000m at intervals of bm to km. Based on the continuous three-dimensional surface fitted by the discrete points, the wellhead temperature contour cloud map is formed after being projected onto the coordinate plane of the influencing factors.

[0052] Furthermore, the wellhead temperature prediction chart mentioned in step 5 includes a three-dimensional surface for predicting wellhead temperature and a contour map of wellhead temperature. The three-dimensional surface is T = f(o, h), where T represents the predicted wellhead temperature. The coordinate axes of the influencing factors represent the daily fluid production (o) and the depth of the insulated tubing (h), respectively. The three-dimensional surface T = f(o, h) determines the relationship between the daily fluid production, the depth of the insulated tubing, and the wellhead temperature. Furthermore, when designing production parameters, once the daily fluid production (o) and the depth of the insulated tubing (h) are determined, the wellhead temperature T can be predicted. If the wellhead temperature T is less than the lowest wellhead temperature T0, the prediction will be successful. l If the daily fluid production and the depth of the insulated tubing designed by this parameter are unreasonable, it is necessary to increase the daily fluid production or the depth of the insulated tubing; the wellhead temperature contour map is the projection of the three-dimensional surface T=f(o,h) onto the coordinate axes o, h plane;

[0053] Preferably, in step 5, 5 ≤ a ≤ 10, 100 ≤ b ≤ 800;

[0054] Further, the calculation method for the maximum depth k of the insulated tubing in the wellhead temperature prediction chart in step 5 is as follows: the daily production is 80t / d, and the depth of the insulated tubing is increased from 2000m to km in 500m intervals. The data obtained on site is substituted into formula (16) to obtain the curve of wellhead temperature change with the depth of the insulated tubing. When the wellhead temperature increase rate q is ≤0.003 for every 500m increase in the depth of the insulated tubing, the depth k of the insulated tubing is the maximum depth. When it is greater than this depth, it is considered that the wellhead temperature no longer increases with the increase in the depth of the insulated tubing. The calculation method for the wellhead temperature increase rate q is as shown in formula (17).

[0055]

[0056] In the formula: q is the rate of increase in wellhead temperature, which is dimensionless; T k The wellhead temperature (°C) is given when the insulated tubing is lowered to a depth of km. k-500 The wellhead temperature (°C) is the temperature at which the insulated tubing is lowered to k-500m.

[0057] Step 6: Design parameters for daily fluid production and depth of insulated tubing, when the on-site heavy oil extraction temperature needs to reach the minimum wellhead temperature T. l At that time, based on the wellhead temperature prediction chart, T was fitted. l Boundary curve T for minimum daily fluid production and minimum tubing depth at temperature l =g(o,h), which provides a design method for daily fluid production and tubing insertion depth parameters on site;

[0058] Furthermore, the boundary curve T l =g(o,h) is obtained from the three-dimensional surface T = f(o,h), that is, when T = T l At that time, T l =f(o,h)=g(o,h), indicating that the minimum wellhead temperature T is satisfied. l The relationship between daily fluid production *o* and the depth of the insulated tubing *h*; the parameter design is based on the daily fluid production *o* and the depth of the insulated tubing *h*. Since increasing both the daily fluid production *o* and the depth of the insulated tubing *h* will increase the temperature of the heavy oil when it reaches the wellhead, therefore, the boundary curve T... l =g(o,h) can be used to calculate the condition that satisfies T l At this time, ① after determining the daily liquid production, then according to T l =g(o,h) calculates the minimum insertion depth h of the insulation oil pipe. min When the depth of the insulation oil pipe is greater than h min At that time, although the wellhead temperature was greater than T l However, this will cause economic losses. ② After determining the depth of the insulation oil pipe, at this time, according to T... l=g(o,h) calculates the daily liquid production as the minimum daily liquid production o. min .

[0059] The present invention has the following advantages due to the adoption of the above technical solutions:

[0060] (1) This method establishes a mathematical model of the temperature field of the wellbore of heavy oil wells with insulated tubing. With a variety of lining materials to choose from, the temperature field mathematical model can be used to calculate the temperature of heavy oil reaching the wellhead under different combinations of lining materials, providing a basis for the selection of insulated tubing lining materials.

[0061] (2) The method also established a wellhead temperature prediction chart. From the chart, on the one hand, the temperature of heavy oil reaching the wellhead can be predicted based on the depth of the insulated tubing and the daily production volume. On the other hand, the boundary curve when the minimum wellhead temperature is required on site can be determined. Furthermore, the minimum depth of the insulated tubing or the minimum daily production volume can be determined, providing guidance for the parameter design optimization of on-site mining. Attached Figure Description

[0062] Figure 1 This is a method for establishing and applying wellhead temperature prediction charts;

[0063] Figure 2 This is a schematic diagram of the well shaft structure;

[0064] Figure 3 These are curves showing the temperature variation of heavy oil fluid with depth under different scenarios;

[0065] Figure 4 It is a curve showing the change in wellhead temperature with the depth of the insulated tubing;

[0066] Figure 5 It is a three-dimensional surface plot of wellhead temperature;

[0067] Figure 6 It is a contour map of wellhead temperature;

[0068] Explanation of reference numerals in the attached diagram: 1-Layer 1 is heavy oil fluid; 2-Layer 2 is tubing anti-corrosion layer; 3-Layer 3 is tubing insulation layer; 4-Layer 4 is tubing anti-corrosion layer; 5-Layer 5 is tubing; 6-Layer 6 is annular mixed with light oil; 7-Layer 7 is oil layer casing; 8-Layer 8 is cement sheath; 9-Layer 9 is technical casing; 10-Layer 10 is cement sheath. Detailed Implementation

[0069] The present invention will now be described in detail with reference to the accompanying drawings and specific embodiments.

[0070] Step 1: Geometric dimensions r of each solid layer 2i and r 1i Given that the thermal conductivity λ of each solid layer is... iGiven: the inner diameter of the second layer of tubing anti-corrosion layer is 0.0580m; the inner diameter of the third layer of tubing insulation layer is 0.0620m; the inner diameter of the fourth layer of tubing anti-corrosion layer is 0.07m; the inner diameter of the fifth layer of tubing is 0.076m; the outer diameter of the fifth layer of tubing is 0.0889m; the inner diameter of the seventh layer of casing is 0.1683m; the inner diameter of the eighth layer of cement ring is 0.1937m; the outer diameter of the eighth layer of cement ring is 0.25088m; the inner diameter of the ninth layer of technical casing is 0.25088m; the inner diameter of the tenth layer of cement ring is 0.2731m; the inner diameter of the tenth layer of cement ring is 0.3461m.

[0071] ①The heat transfer flow rate of each solid layer in the wellbore can be calculated according to formula (1); the heat transfer flow rate of each solid layer is respectively the heat transfer flow rate Φ of the second layer of tubing anti-corrosion layer. S2 The third layer is the oil pipe insulation layer, with a heat transfer flow rate Φ. S3 The fourth layer is the oil pipe anti-corrosion layer, with a heat transfer flow rate Φ. S4 The 5th layer is the oil pipe, and the 7th layer is the oil layer casing. Heat transfer flow rate Φ S7 The 8th layer has a cement ring heat transfer flow rate Φ S8 Heat transfer flow rate Φ of the 9th layer technical casing S9 Heat transfer flow rate Φ of the 10th layer cement ring S10 ;

[0072] ②The heat flow rate Φ of the convective heat transfer between the first layer of heavy oil fluid and the second layer of oil pipe anti-corrosion layer can be calculated according to equation (2). S1 ;

[0073] ③According to equation (3), the heat flow Φ of convective heat transfer between the 6th layer annulus with diluted oil and the 5th layer oil pipe and the 7th layer oil casing can be calculated. S6 ;

[0074] Step 2: Combine equations (4) and (5) to obtain the temperature difference T1-T2 between the first layer of heavy oil fluid in the first part of the wellbore and the outer wall of the eighth layer. 1 Furthermore, the radial total heat transfer coefficient k1 of the first part of the wellbore is obtained; by combining equations (4) and (5), the temperature difference T1-T2 between the first layer of heavy oil fluid and the outer wall of the tenth layer in the second part of the wellbore is obtained. 2 Furthermore, the radial total heat transfer coefficient k2 of the second part of the wellbore is obtained;

[0075] Step 3: Obtain field data, including the formation thermal conductivity λ. e α, formation thermal diffusivity, and the outer radius of the first part of the wellbore. (Outer diameter of the 8th layer of cement ring), outer radius of the second part of the well shaft (Outer diameter of the 10th cement ring), production time t, specific heat of well fluid at constant pressure C pm geothermal gradient g T Formation temperature T at the bottom of the wellw Substituting into equations (10) to (16), we obtain the temperature T1 of any cross section of the heavy oil fluid in the tubing;

[0076] Step 4: Two types of anti-corrosion coating materials are provided on-site: polyethylene and POK polyketone, with thermal conductivity of 0.5 W / (m·℃) and 0.2 W / (m·℃), respectively. Two types of insulation materials are also provided: polyethylene foam shell and aerogel, with thermal conductivity of 0.2023 W / (m·℃) and 0.02 W / (m·℃), respectively. Four combinations of the anti-corrosion and insulation materials are provided, as follows:

[0077] Option 1: POK polyketide, aerogel;

[0078] Option 2: POK polyketone and polyethylene foam shell;

[0079] Option 3: Polyethylene, polyethylene foam shell;

[0080] Option 4: Polyethylene, Aerogel;

[0081] Based on the wellbore temperature calculation method established by equations (1) to (16), the temperature variation curve of the first layer of heavy oil fluid with depth is plotted as follows: Figure 3 As shown, the temperature of the heavy oil reaching the wellhead in Scheme 1 is 64.7℃, the temperature at the wellhead in Scheme 2 is 60.9℃, the temperature at the wellhead in Scheme 3 is 42.7℃, and the temperature at the wellhead in Scheme 4 is 44.5℃. Scheme 1 has the highest wellhead temperature, which means that POK polyketide and aerogel are the optimal tubing lining materials.

[0082] Step 5: Establish a wellhead temperature prediction chart, with a set value of 10 and b set value of 500. The daily production volume is 80t / d. The depth of the insulated tubing is increased from 2000m to km in 500m intervals. Substitute the data obtained on site into equations (1) to (16) to obtain the curve of wellhead temperature variation with the depth of the insulated tubing, as shown in the figure. Figure 4 As shown, when k = 5500m, T 5500 =75.79℃, T 5000 =75.49, substituting into equation (17) yields an amplification rate q = 0.004, which is greater than 0.003; when k = 6000m, T 6000 =75.94℃, T 5500 =75.79, substituting into equation (17) yields an increase rate q = 0.00197, which is less than 0.003; therefore, the maximum depth of the insulated tubing is 6000m. Beyond 6000m, the wellhead temperature increase rate is extremely small, which will only increase costs.

[0083] At this time, the daily liquid production *o* increases from 50 *t / d* to 100 *t / d at intervals of 10 *t / d, and the depth *h* of the insulated oil pipe increases from 2000 *m* to 6000 *m* at intervals of 500 *m*. Based on the discrete point fitting of the continuous three-dimensional surface *T = f(o,h)*, as shown... Figure 5 As shown, the wellhead temperature contour map is formed after projection onto the coordinate plane of influencing factors. Figure 6 As shown;

[0084] Further from Figure 5 The relationship between daily fluid production, the depth of the insulated tubing, and the wellhead temperature can be obtained. On the other hand, when designing production parameters, after clarifying the daily fluid production (o) and the depth of the insulated tubing (h), the wellhead temperature (T) can be predicted.

[0085] Step 6: When the on-site heavy oil extraction temperature needs to reach the minimum wellhead temperature T l =75℃, according to the wellhead temperature prediction chart ( Figure 5 and Figure 6 The minimum daily liquid production and minimum tubing depth boundary curves at 75℃ are fitted as shown in equation (18).

[0086]

[0087] Combination Figure 6 According to equation (18), when the minimum wellhead temperature is 75℃ and the daily fluid production is not higher than 100t / d, the depth of the insulated tubing should be at least 3500m; when the depth of the insulated tubing is 6000m, the minimum daily fluid production should be greater than 72t / d; ① Assuming the daily fluid production is 80t / d, substituting into equation (18) yields that the minimum depth of the insulated tubing is approximately h. min =4534m. Beyond this depth, the wellhead temperature will increase, but so will the cost; ② Assuming the insulated tubing is run to a depth of 5000m, substituting into equation (18) yields a minimum daily fluid production of approximately o. min = 76.1t / d.

[0088] The basic method and main features of the present invention have been described above. Those skilled in the art should understand that the embodiments have provided a detailed description of the invention. Modifications or equivalent substitutions of some technical features may be made without departing from the spirit and scope of the invention, and all such modifications or substitutions fall within the scope of the present invention as claimed. The scope of protection of the present invention is defined by the claims and their equivalents.

Claims

1. A method for establishing and applying a wellhead temperature prediction chart, characterized in that, The specific steps include: Step 1: Calculate the heat transfer flow rate of each layer of the wellbore; the wellbore is divided into two parts along its axial direction. The first part, from the inside out: the first layer is heavy oil fluid, the second layer is the tubing anti-corrosion layer, the third layer is the tubing insulation layer, the fourth layer is the tubing anti-corrosion layer, the fifth layer is the tubing, the sixth layer is the annulus mixed with light oil, the seventh layer is the oil layer casing, and the eighth layer is the cement sheath; the second part has an additional ninth layer of technical casing and a tenth layer of cement sheath compared to the first part; among them, the second layer (tubing anti-corrosion layer), the third layer (tubing insulation layer), and the fourth layer (tubing anti-corrosion layer) constitute the tubing liner; ① Layers 2, 3, 4, 5, 7, 8, 9, and 10 are solid layers, with radial heat flow Φ Si As in equation (1); Where: Φ Si Let W be the radial heat flux of the i-th layer; T be the heat flux of the i-th layer. 1i T represents the temperature of the inner wall of the i-th layer, in °C. 2i r is the temperature of the outer wall of the i-th layer, in °C; 1i Let r be the inner radius of the i-th layer, m; 2i Let λ be the outer radius of the i-th layer, m; i ΔL is the thermal conductivity of the i-th layer, W / (m·℃); ΔL is the unit length, m; ② The heat flow rate Φ of convective heat transfer between the first layer of heavy oil fluid and the second layer of oil pipe anti-corrosion layer S1 As in equation (2); F S1 =2πr 12 h1(T1-T 12 )ΔL (1) Where: Φ S1 h1 is the heat flow rate of the convective heat transfer between the first layer of heavy oil fluid and the second layer of oil pipe corrosion protection layer, in W; h1 is the convective heat transfer coefficient between the first layer of heavy oil fluid and the second layer of oil pipe corrosion protection layer, in W / (m²). 2 ·℃); T1 is the temperature of the first layer of heavy oil fluid, ℃; T 12 The temperature of the inner wall of the second layer of the oil pipe corrosion protection layer is ℃; r 12 The inner radius of the second layer is m; ③ The heat flow rate Φ of the convective heat transfer between the 6th layer annulus with diluted oil and the 5th layer oil pipe and the 7th layer oil casing S6 As in equation (3); F S6 =2πr 25 h6(T 25 -T 17 )ΔL (3) Where: Φ S6 h6 is the heat flow rate of convective heat transfer between the 6th layer annular layer diluted oil and the 5th layer oil pipe and the 7th layer oil casing, in W; h6 is the convective heat transfer coefficient between the 6th layer annular layer diluted oil and the 5th layer oil pipe and the 7th layer oil casing, in W / (m2). 2 ·℃); T 25 Temperature of the outer wall of the fifth oil pipe, in °C; T 17 The temperature of the inner wall of the casing in the 7th oil layer is ℃; r 25 Let the outer radius of the 5th tubing layer be m; Step 2: Calculate the overall heat transfer coefficient of the wellbore. Heat flow rate Φ of radial heat conduction in wellbore S As in equation (4); Where: Φ S Radial heat flow rate of the wellbore, W; The outer radius of the j-th section of the wellbore, in meters; k j Let J be the overall heat transfer coefficient for the j-th part, W / (m²). 2 ·℃); Let J be the temperature of the outer wall of the j-th section of the wellbore, in °C. Substitute the heat flow of each layer from the 1st to the 10th layer obtained from ①②③ in step 1 and equation (4) into equation (5); F S =Φ S1 =Φ S6 =Φ Si (i=2,3,4,5,7,8,9,10) (5) The temperature difference T1-T2 between the first layer of heavy oil fluid in the first part of the wellbore and the outer wall temperature of the eighth layer is obtained according to equation (5). 1 As in equation (6); In the formula: T2 1 The temperature of the outer wall of the first section of the wellbore is in °C; r 12 r 22 These are the inner and outer radii of the second layer, respectively, in meters (m) and r. 13 r 23 These are the inner and outer radii of the 3rd layer, respectively, in meters (m) and r. 14 r 24 These are the inner and outer radii of the 4th layer, respectively, in meters (m); r 15 r 25 These are the inner and outer radii of the 5th layer, respectively, in meters (m); r 16 r 26 These are the inner and outer radii of the 6th layer annulus with diluted oil, respectively, in meters (m); r 17 r 27 These are the inner and outer radii of the 7th layer, respectively, in meters (m); r 18 r 28 λ1, λ2, λ3, λ4, λ5, λ7, and λ8 are the inner and outer radii of the 8th layer, respectively, in meters; λ2, λ3, λ4, λ5, λ7, and λ8 are the thermal conductivity of the media in the 2nd, 3rd, 4th, 5th, 7th, and 8th layers, respectively, in W / (m·℃). Combining equations (5) and (6), we obtain the first part of the radial total heat transfer coefficient k1 as shown in equation (7); According to equation (5), the temperature differences T1-T2 on the outer side of the first to tenth layers of the second part of the wellbore are obtained respectively. 2 As in equation (8); In the formula: T2 2 Temperature outside the second section of the wellbore, in °C; r 19 r 29 These are the inner and outer radii of the 9th layer, respectively, in meters (m); r 110 r 210 These are the inner and outer radii of the 10th layer, respectively, in meters; λ9, λ 10 The values ​​are the thermal conductivity of the 9th and 10th layers, respectively, in W / (m·℃). Combining equations (5) and (8), we obtain the second part of the radial total heat transfer coefficient k2 as shown in equation (9); Step 3: Calculate the temperature field in the wellbore; In the first and second wellbore sections, the radial heat transfer Q1 from the fluid to the outer surface of the cement sheath is as shown in equation (10); In the formula: Q1 is the radial heat transfer within the wellbore, in W; Let k be the outer radius of the j-th section of the wellbore, in meters. lj T1 is the overall heat transfer coefficient of the j-th part, W / (m·℃); T1 is the temperature of the first layer of heavy oil fluid, ℃; dj represents the outer surface temperature of the j-th section of the wellbore, in °C; dz represents the length of the fluid micro-element inside the tubing. The radial heat transfer from the outer surface of the wellbore to the formation is Q2 as shown in equation (11); in: In the formula: Q2 is the radial heat transfer from the wellbore exterior to the formation, W; T3 is the formation temperature, °C; α is the formation thermal diffusivity, dimensionless; t is the production time, h; λ e is the thermal conductivity of the formation, W / (m·℃); The heat transferred from the wellbore to the outer surface of the cement is equal to the heat transferred from the outer surface of the cement to the surrounding strata, i.e., Q1 = Q2. Thus, by combining equations (10) and (11), we obtain equation (13). in: T3=T w -g T z(15) In the formula: C pm σ represents the isobaric specific heat of the well fluid, J / (kg·℃); o represents the daily fluid production, t / d; g T The geothermal gradient is expressed in °C / m and T. w Z represents the formation temperature at the bottom of the well, in °C; Z represents the depth, in meters. At the bottom of the well, z = 0, T1 = T3 = T w The temperature T1 of any cross section of the heavy oil fluid in the tubing is obtained as shown in equation (16); Step 4: Select the tubing lining material and determine the thermal conductivity. The tubing lining material includes the tubing anti-corrosion layer material and the tubing insulation layer material. ① There is only one type of tubing anti-corrosion layer material and only one type of tubing insulation layer material provided on site. Then determine the thermal conductivity of the tubing anti-corrosion layer material and the tubing insulation layer material and proceed to step 5. ② There are multiple choices of tubing anti-corrosion layer material or tubing insulation layer material provided on site. The tubing anti-corrosion layer material and the tubing insulation layer material can be combined in pairs to form multiple schemes. After determining the thermal conductivity, calculate the different schemes according to formulas (1) to (16) when the daily fluid production is 80t / d, the insulation tubing is lowered to a depth of 3000m, and the bottom temperature is 100℃. Plot the curve of the change of heavy oil fluid temperature with depth under different schemes and obtain the wellhead temperature. The scheme with the highest temperature when the fluid reaches the wellhead is the optimal scheme. The corresponding tubing anti-corrosion layer material and the tubing insulation layer material are the optimal tubing lining materials. After selecting the optimal tubing lining material, proceed to step 5. Step 5: Establish a wellhead temperature prediction chart, taking the daily production volume o and the depth of the insulated tubing h as influencing factors, and calculate the wellhead temperature according to formula (16); where the daily production volume o increases from 50t / d at intervals of at / d to 100t / d, and the depth of the insulated tubing h increases from 2000m at intervals of bm to km. Based on the continuous three-dimensional surface fitted by the discrete points, the wellhead temperature contour cloud map is formed after being projected onto the coordinate plane of the influencing factors. Step 6: Design parameters for daily fluid production and depth of insulated tubing, when the on-site heavy oil extraction temperature needs to reach the minimum wellhead temperature T. l At that time, based on the wellhead temperature prediction chart, T was fitted. l Boundary curve T for minimum daily fluid production and minimum tubing depth at temperature l =g(o,h), which provides a design method for parameters such as daily fluid production and tubing insertion depth on site.

2. The method for establishing and applying a wellhead temperature prediction chart according to claim 1, characterized in that, The wellhead temperature prediction chart mentioned in step 5 includes a three-dimensional surface for predicting wellhead temperature and a contour map of wellhead temperature. The three-dimensional surface is T = f(o,h), where T represents the predicted wellhead temperature. The coordinate axes of the influencing factors represent the daily fluid production (o) and the depth of the insulated tubing (h), respectively. The three-dimensional surface T = f(o,h) determines the relationship between the daily fluid production, the depth of the insulated tubing, and the wellhead temperature. Furthermore, when designing production parameters, once the daily fluid production (o) and the depth of the insulated tubing (h) are determined, the wellhead temperature T can be predicted. If the wellhead temperature T is less than the lowest wellhead temperature T0, the prediction will be successful. l If the designed daily production volume and insulation tubing depth are unreasonable, it is necessary to increase the daily production volume or the insulation tubing depth; the wellhead temperature contour map is the projection of the three-dimensional surface T=f(o,h) onto the coordinate axes o and h plane.

3. The method for establishing and applying a wellhead temperature prediction chart according to claim 1, characterized in that, In step 5, 5 ≤ a ≤ 10, 100 ≤ b ≤ 800.

4. The method for establishing and applying a wellhead temperature prediction chart according to claim 1, characterized in that, The calculation method for the maximum depth k of the insulated tubing in the wellhead temperature prediction chart in step 5 is as follows: the daily production is 80t / d, and the depth of the insulated tubing is increased from 2000m to km in 500m intervals. The data obtained on site is substituted into formula (16) to obtain the curve of wellhead temperature change with the depth of the insulated tubing. When the depth of the insulated tubing increases by 500m, the rate of increase of wellhead temperature q ≤ 0.

003. At this time, the depth of the insulated tubing k is the maximum depth. When it is greater than this depth, it is considered that the wellhead temperature will no longer increase. The calculation method for the rate of increase of wellhead temperature q is as shown in formula (17). In the formula: q is the rate of increase of wellhead temperature, which is dimensionless; T k The wellhead temperature (°C) is given when the insulated tubing is run to a depth of km. k-500 The wellhead temperature (°C) is the temperature at which the insulated tubing is lowered to k-500m.

5. The method for establishing and applying a wellhead temperature prediction chart according to claim 1, characterized in that, The boundary curve T mentioned in step 6 l =g(o,h) is obtained from the three-dimensional surface T = f(o,h), that is, when T = T l At that time, T l =f(o,h)=g(o,h), indicating that the minimum wellhead temperature T is satisfied. l The relationship between daily fluid production *o* and the depth of the insulated tubing *h*; the parameter design is based on the daily fluid production *o* and the depth of the insulated tubing *h*. Since increasing both the daily fluid production *o* and the depth of the insulated tubing *h* will increase the temperature of the heavy oil when it reaches the wellhead, therefore, the boundary curve T... l =g(o,h) can be used to calculate the condition that satisfies T l At this time, ① after determining the daily liquid production, then according to T l =g(o,h) calculates the minimum insertion depth h of the insulation oil pipe. min When the depth of the insulation oil pipe is greater than h min At that time, although the wellhead temperature was greater than T l However, this will cause economic losses. ② After determining the depth of the insulation oil pipe, at this time, according to T... l =g(o,h) calculates the daily liquid production as the minimum daily liquid production o. min .

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