Rapid method for evaluating yield increasing effect and economical efficiency of underground electric heating of horizontal well

Abstract

The invention provides a rapid method for evaluating the yield increasing effect and economical efficiency of underground electric heating of a horizontal well, and belongs to the technical field of oil and gas field development. Comprising the following steps that geological reservoir parameters of a target oil field, thermophysical parameters of rock fluid, temperature and pressure monitoring data and oil well parameters of a target oil well are collected; improving a horizontal shaft-oil reservoir heat transfer simulation device; determining the influence of oil reservoir fluid parameters and oil well parameters on the heating condition; carrying out sensitivity analysis on oil reservoir fluid parameters and oil well parameters which influence the heating condition; respectively establishing two-dimensional curve charts of the relationship between the influence parameters and the oil increase percentage and the relationship between the influence parameters and the input-output ratio; and determining the underground electric heating yield increasing effect and economical efficiency evaluation indexes of the horizontal well. According to the method, based on the formation temperature and pressure conditions and the reservoir temperature distribution rule of horizontal well underground electric heating in the formation liquid supply state, the influence of different factors on the oil increasing percentage and the input-output ratio before and after electric heating is considered, and an important basis is provided for productivity prediction and effect evaluation of horizontal well underground electric heating.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and in particular to a rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells. Background Technology

[0002] Bohai Oilfield has conducted downhole electric heating tests on horizontal wells in heavy oil fields with formation crude oil viscosity ranging from 350 mPa·s to 1000 mPa·s, achieving certain production enhancement effects. However, due to differences in reservoir conditions and production parameters among different wells, the actual heating power during the heating process varies, resulting in significant differences in production enhancement among wells: heating power ranges from 0.1 kW / m to 1.0 kW / m, bottomhole flow temperature ranges from 9.0℃ to 43.9℃, and the percentage increase in oil production ranges from 10% to 105%. Currently, there is limited research on the reservoir temperature variation patterns and influencing factors of downhole electric heating in horizontal wells, a lack of understanding of the adaptability of this technology, and economic constraints in offshore oilfield development. It is necessary to develop a rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells, based on formation temperature and pressure conditions and formation fluid supply status, and fully considering the impact of different factors on the percentage increase in oil production and the input-output ratio before and after electric heating. Summary of the Invention

[0003] In view of this, the present invention aims to propose a rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells, which can accurately predict the percentage increase in oil production and the input-output ratio of downhole electric heating in horizontal wells, and quickly evaluate the production enhancement effect and economic efficiency.

[0004] To achieve the above objectives, the technical solution of the present invention is as follows: a rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells, comprising the following steps: S1. Collect geological reservoir parameters, rock fluid thermal properties, temperature and pressure monitoring data of the target oilfield, as well as parameters of the oil wells where downhole electric heating of horizontal wells is implemented; S2. Improve the horizontal wellbore-reservoir heat transfer simulation device; add an injection point in the middle of the inner wall of the cylindrical sand-filled cylinder of the simulation device to simulate the near-well reservoir fluid supply under actual formation temperature and pressure conditions with downhole electric heating in horizontal wells. S3. Using an improved simulation device, conduct a physical simulation experiment of downhole electric heating in horizontal wells under the formation temperature and pressure system of the target oilfield, simulate the near-well reservoir heating field distribution, and determine the influence of reservoir fluid parameters and well parameters on the heating conditions. S4. Based on experimental understanding, establish a numerical simulation of typical well reservoirs at the wellbore level, study the changes in heating power, temperature and production capacity during horizontal well electric heating, and conduct sensitivity analysis on reservoir fluid parameters and well parameters that affect the heating conditions. S5. Statistical simulation results, inputting economic parameters such as equipment cost, electricity cost and oil price, calculate the percentage increase in oil production and the input-output ratio of horizontal well electric heating; establish two-dimensional curves showing the relationship between the influencing parameters and the percentage increase in oil production and the input-output ratio. S6. On the two-dimensional curve chart, based on the geological reservoir and production parameters of the target well, find the corresponding percentage increase in oil production and the input-output ratio, and determine the evaluation indicators of the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells.

[0005] Furthermore, step S1 includes: Based on actual drilling and testing, the geological reservoir parameters of the target oilfield were statistically analyzed, including porosity, permeability, reservoir pressure, and reservoir temperature. Based on analytical test results, the rock-fluid thermal properties of the target oilfield were statistically analyzed, including the specific heat and thermal conductivity of rocks, the density, viscosity, specific heat and thermal conductivity of crude oil, and the density, viscosity, specific heat and thermal conductivity of water. The well parameters of the target oil wells were also statistically analyzed, including the horizontal section length, production rate, and water cut.

[0006] Furthermore, step S2 includes simulating the reservoir rock structure by filling the sand-filling cylinder with sand; placing a horizontal pipe at the center of the sand-filling cylinder to simulate a horizontal wellbore, the horizontal pipe being connected to the production system to simulate horizontal well production; fixing a resistance heater outside the horizontal pipe to simulate a heating cable, the resistance heater having a heating power of 0~1.5kW / m and a heating temperature of 0~500℃; uniformly deploying 30 thermocouples inside the sand-filling model to collect temperature data; and setting a thermal compensation insulating sleeve outside the sand-filling cylinder, the thermal compensation insulating sleeve having both heating and insulation functions, the heating temperature of the thermal compensation insulating sleeve being 0~500℃, used to establish the initial reservoir temperature and to insulate the sand-filling model. The core component of the simulation device, the cylindrical sand-filling cylinder, was modified. Eight liquid injection points were evenly deployed in the middle of the inner wall of the cylindrical sand-filling cylinder along the circular tangent to inject oil-water mixture into the sand-filling model. The injection rate was 0~300ml / min, which can simulate the near-well reservoir fluid supply state of horizontal wells under exhaustion or stable displacement conditions.

[0007] Furthermore, in step S3, the physical simulation experiment process of downhole electric heating in horizontal wells under the formation temperature and pressure system includes experimental preparation, model sand filling, establishment of initial pressure, saturation and temperature fields, and electric heating production; The model sand filling process includes: using a wet filling method to fill the sand filling cylinder with the required mesh size of quartz sand for the experiment, placing the horizontal pipe and resistance heater and connecting the wires, tightening and sealing, and then connecting the injection and extraction pipelines. Establishing the initial pressure, saturation, and temperature fields includes: simulating the original formation pressure by adjusting the back pressure valve, establishing the initial oil-water saturation using an oil-water mixed injection method, and establishing the original formation temperature by activating the thermal compensation insulation jacket; once the initial pressure, saturation, and temperature fields of the sand-filled model reach the required experimental values ​​and stabilize, the experiment can begin. The electric heating production process includes: adjusting the heating power of the cable heater to the value corresponding to the experimental parameters, controlling the liquid production rate with a back pressure valve, adjusting the injection rate of the liquid injection point in the middle of the inner wall of the sand-filled model to the value corresponding to the experimental parameters, collecting the temperature data inside the sand-filled model through thermocouples and transmitting it to the computer temperature measurement program, and recording the temperature and energy consumption data of the experiment throughout the process. After the experiment, turn off the cable heater, open the compensation sleeve, and cool the sand-filled model. The temperature data collected by the computer temperature measurement program is analyzed. Based on the temperature distribution characteristics of the wellbore and near-well reservoir during downhole electric heating of horizontal wells, the distribution law of the heating field is derived, and the influence of reservoir fluid parameters and well parameters on the heating field distribution is qualitatively analyzed.

[0008] Furthermore, step S4 includes: combining the heating field distribution pattern obtained from the experiment, as well as the affected reservoir fluid parameters and well parameters, to establish a numerical model at the wellbore level for typical wells based on the target oilfield parameters. This numerical model includes wellbore simulation based on the actual well completion structure and in-depth description of the near-well reservoir. Using this numerical model, the changes in oil production before and after the implementation of downhole electric heating in horizontal wells can be simulated, and the cumulative oil production can be statistically analyzed to calculate the increase in oil production before and after electric heating. Based on the actual situation of the target oilfield, 3 to 4 levels of change are selected for the reservoir fluid parameters and well parameters that affect the heating status, respectively, to simulate the changes in cumulative oil production and calculate the increase in oil production. Sensitivity analysis of the influencing parameters on the increase in oil production is carried out.

[0009] Furthermore, in step S5, the percentage increase in oil production over three years and the input-output ratio are used as indicators for evaluating the production increase effect and economic efficiency, respectively; the formula for calculating the percentage increase in oil production is as follows: (1) In the formula, M represents the percentage increase in oil consumption, %; The cumulative oil production over three years of cold extraction development is [amount missing]. The cumulative oil production over three years using downhole electric heating in horizontal wells under the same production system is calculated in square meters. The formula for calculating the input-output ratio is as follows: (2) In the formula, IOR is the input-output ratio; E represents the cost of the downhole electric heating equipment for the horizontal well, in yuan; E represents the electricity consumed by the electric heating equipment during oil well production, in kW·h. Electricity cost, yuan; The price is for oil, in yuan.

[0010] Compared to existing technologies, the rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells, as described in this invention, has the following advantages: This invention, through improvements to the simulation device, simulates formation temperature and pressure conditions and near-wellbore reservoir fluid supply in horizontal wells, conforming to the actual production conditions of horizontal wells. Using the improved simulation device, the reservoir temperature distribution law of downhole electric heating in horizontal wells was studied and clarified, and the main factors affecting temperature distribution were identified. Based on this, the relationship between different factors and the percentage increase in oil production and the input-output ratio before and after electric heating was established, clarifying the production enhancement effect and adaptability of downhole electric heating technology in horizontal wells, providing an important basis for the production capacity prediction and effect evaluation of downhole electric heating in horizontal wells.

[0011] (1) This invention clarifies the distribution law of the downhole electric heating temperature field and the influencing factors of horizontal wells through physical simulation experiments under formation temperature and pressure conditions and fluid supply conditions; (2) This invention uses fine reservoir numerical simulation at the wellbore level, combined with actual economic parameters such as equipment cost, electricity cost and oil price, to accurately predict the percentage increase in oil production and the input-output ratio of downhole electric heating in horizontal wells, and quickly evaluate the production increase effect and economic efficiency. It is of great significance for the efficient development of thermal recovery of heavy oil reservoirs and has broad application prospects. Attached Figure Description

[0012] The accompanying drawings, which form part of this invention, are used to provide a further understanding of the invention. The illustrative embodiments of the invention and their descriptions are used to explain the invention and do not constitute an undue limitation of the invention. In the drawings: Figure 1 This is a flowchart of a rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells, as described in this invention. Figure 2 This is a schematic diagram of the improved part of the horizontal wellbore-reservoir heat transfer simulation device in this invention; Figure 3 This refers to the temperature field distribution in the near-well zone during the well shut-in and preheating stage in Example 1. Figure 4 This refers to the temperature field distribution in the near-wellbore zone during the production stage in Example 1. Figure 5 This is a graph showing the percentage increase in oil production from electric heating in the S oilfield in Example 1; Figure 6 This is a graph showing the input-output ratio of electric heating in the S oilfield in Example 1. Detailed Implementation

[0013] The invention will now be described in further detail with reference to the accompanying drawings, so that those skilled in the art can implement it based on the description.

[0014] It should be understood that terms such as “having,” “comprising,” and “including” as used herein do not exclude the presence or addition of one or more other elements or combinations thereof.

[0015] like Figure 1 As shown, this invention provides a rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells. By improving experimental equipment, it simulates the near-wellbore reservoir conditions under actual formation temperature and pressure conditions and formation fluid supply, identifying the main influencing factors. Reservoir numerical simulation is used to determine power consumption and oil production under different influencing factors. The input-output ratio is calculated by combining actual equipment costs, electricity costs, and oil prices. Two-dimensional curves depicting the relationship between reservoir, production parameters, percentage oil production increase, and input-output ratio are established to quickly determine the evaluation indicators for the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells, providing a basis for the design, effect analysis, and economic evaluation of downhole electric heating technology in horizontal wells. Specifically, a rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells includes the following steps: S1. Collect geological reservoir parameters, rock fluid thermal properties, temperature and pressure monitoring data of the target oilfield, as well as parameters of the oil wells where downhole electric heating of horizontal wells is implemented; Specifically, based on actual drilling and testing results, the geological reservoir parameters of the target oilfield are statistically analyzed, including porosity, permeability, reservoir pressure, and reservoir temperature. Based on analytical and testing results, the rock-fluid thermal properties of the target oilfield are statistically analyzed, including the specific heat and thermal conductivity of rocks, the density, viscosity, specific heat and thermal conductivity of crude oil, and the density, viscosity, specific heat and thermal conductivity of water. The well parameters of the target oil wells are statistically analyzed, including the horizontal section length, production rate, and water cut.

[0016] S2. Improved horizontal wellbore-reservoir heat transfer simulation device; such as Figure 2 As shown, an injection point is added to the middle of the inner wall of the cylindrical sand-filling cylinder of the simulation device to inject liquid into the sand-filling model, simulating the near-wellbore reservoir liquid supply situation of a horizontal well with downhole electric heating under actual formation temperature and pressure conditions. Specifically, the horizontal wellbore-reservoir heat transfer simulation device can be used to simulate the downhole electrically heated wellbore and reservoir heating conditions of horizontal wells under formation temperature and pressure systems. The core component is a cylindrical sand-filled cylinder, which includes a model container and an injection-production system.

[0017] Model Container: A cylindrical sand-filling cylinder with an internal diameter of 178mm and a length of 500mm, with a maximum pressure resistance of 20MPa and a temperature resistance of 250℃. Sand is filled inside the cylinder to simulate the reservoir rock structure. A horizontal pipe, simulating a horizontal wellbore, is placed at the center of the sand-filling cylinder. This horizontal pipe connects to the production system to simulate horizontal well production. A resistance heater, simulating a heating cable, is fixed outside the horizontal pipe. The resistance heater has a heating power of 0~1.5kW / m and a heating temperature of 0~500℃. It should be noted that the resistance heater and the horizontal pipe are not connected; they are placed side-by-side. Thirty thermocouples are evenly distributed inside the sand-filling model to collect temperature data. A thermal compensation insulating sleeve is installed outside the sand-filling cylinder. This sleeve serves both heating and insulation functions, with a heating temperature of 0~500℃, and is used to establish the initial reservoir temperature and insulate the sand-filling model. The injection and production system consists of an ISCO high-precision plunger pump, pressure sensors, and injection and production outlets. It can precisely control the injection and production rates and pressures of fluids such as water, oil, and gas, simulating the actual injection and production process in an oilfield.

[0018] The core component of the simulation device, the cylindrical sand-filling cylinder, is modified. Eight injection points are evenly distributed along the circular tangent in the middle of the inner wall of the cylinder to inject an oil-water mixture into the sand-filling model. The injection rate ranges from 0 to 300 ml / min, simulating the near-wellbore reservoir fluid supply state of horizontal wells under both depletion and stable displacement conditions. The modified cylindrical sand-filling cylinder can be used to simulate actual formation temperature and pressure conditions and the downhole electrically heated wellbore and near-wellbore reservoir heating conditions of horizontal wells under fluid supply conditions. In the description of this invention, unless otherwise stated, "a plurality of" means two or more.

[0019] S3. Using an improved simulation device, conduct a physical simulation experiment of downhole electric heating in horizontal wells under the formation temperature and pressure system of the target oilfield, simulate the near-well reservoir heating field distribution, and determine the influence of reservoir fluid parameters and well parameters on the heating conditions. The reservoir fluid parameters include permeability and crude oil viscosity, while the well parameters include production rate and water cut. These parameters are converted to experimental conditions using similarity criteria. To maintain stable fluid supply during the experiment, the fluid supply rate at the injection point on the inner wall of the sand-filled model is determined based on the production rate of the horizontal well. The production rate at the field scale for the horizontal well is 100 m³ / s. 3 At / d, the production rate under formation conditions converted by the similarity criterion is 138 ml / min, and the replenishment rate to the sand-filled model through the 8 inner wall injection points is 17.25 ml / min.

[0020] In step S3, the physical simulation experiment process of downhole electric heating in horizontal wells under the formation temperature and pressure system includes experimental preparation, model sand filling, establishment of initial pressure, saturation and temperature fields, and electric heating production. The model sand filling process includes: filling the sand filling cylinder with the required mesh size of quartz sand using a wet filling method, placing the horizontal pipe and resistance heater and connecting them, tightening and sealing them, and then connecting the injection pipeline and the extraction pipeline; specifically, the injection pipeline is connected to the injection point on the inner wall of the sand filling pipe, the horizontal pipe is connected to the extraction pipeline, and the resistance heater is connected to the electrical control system. The electrical control system is existing technology, which can not only control the opening or closing of the resistance heater, but also adjust the heating power and heating temperature of the resistance heater.

[0021] Establishing the initial pressure, saturation, and temperature fields includes: simulating the original formation pressure by adjusting the back pressure valve, establishing the initial oil-water saturation using an oil-water mixed injection method, and establishing the original formation temperature by activating the thermal compensation insulation jacket; once the initial pressure, saturation, and temperature fields of the sand-filled model reach the required experimental values ​​and stabilize, the experiment can begin. The electrically heated production process includes: adjusting the heating power of the cable heater to the value corresponding to the experimental parameters, controlling the liquid production rate with a back pressure valve, adjusting the injection rate of the liquid injection point in the middle of the inner wall of the sand-filled model to the value corresponding to the experimental parameters, collecting the temperature data inside the sand-filled model through thermocouples and transmitting it to the computer temperature measurement program, and recording the temperature and energy consumption data of the experiment throughout the process; the computer temperature measurement program is existing technology.

[0022] After the experiment, turn off the cable heater, open the compensation sleeve, and cool the sand-filled model. The temperature data collected by the computer temperature measurement program is analyzed. Based on the temperature distribution characteristics of the wellbore and near-well reservoir during downhole electric heating of horizontal wells, the distribution law of the heating field is derived, and the influence of reservoir fluid parameters and well parameters on the heating field distribution is qualitatively analyzed.

[0023] S4. Based on experimental understanding, establish a numerical simulation of typical well reservoirs at the wellbore level, study the changes in heating power, temperature and production capacity during horizontal well electric heating, and conduct sensitivity analysis on reservoir fluid parameters (permeability and crude oil viscosity) and well parameters (production rate and water cut) that affect the heating conditions. Specifically, a numerical model at the wellbore level was established based on the geological and reservoir parameters of the target oilfield. The mesh in the near-wellbore area was finely refined (mesh size to 0.5m), and a flexible wellbore model was built using CMG software to simulate the complex internal tubing structure of the screen pipe and the installation of the heating cable bundled with the tubing into the horizontal section. CMG software is existing technology. This numerical model can simulate the changes in oil production before and after the implementation of downhole electric heating in horizontal wells, and can statistically analyze the cumulative oil production and calculate the increase in oil production before and after electric heating. Considering the actual conditions of the target oilfield, three to four variation levels were selected for the reservoir fluid parameters and well parameters affecting the heating conditions to simulate cumulative oil production changes and calculate the increase in oil production. A multifactor analysis of variance (ANOVA) was used to conduct a sensitivity analysis of the reservoir fluid parameters and well parameters affecting the heating conditions on the increase in oil production, clarifying the degree of influence of each factor on the increase in oil production. ANOVA is a conventional calculation method well-known to those skilled in the art; the sensitivity of each parameter to the increase in oil production can be determined based on the calculated variance values, so it will not be elaborated further here.

[0024] S5. Statistical simulation results, inputting economic parameters such as equipment cost, electricity cost and oil price, calculate the percentage increase in oil production and the input-output ratio of horizontal well electric heating; establish two-dimensional curves showing the relationship between the influencing parameters and the percentage increase in oil production and the input-output ratio. Considering the economic constraints of offshore oilfield development, the percentage increase in oil production and the input-output ratio over three years are used as indicators for evaluating the production increase effect and economic efficiency, respectively. The formula for calculating the percentage increase in oil production is as follows: (1) In the formula, M represents the percentage increase in oil consumption, %; The cumulative oil production over three years of cold extraction development is [amount missing]. The cumulative oil production over three years using downhole electric heating in horizontal wells under the same production system is calculated in square meters. The formula for calculating the input-output ratio is as follows: (2) In the formula, IOR is the input-output ratio; E represents the cost of the downhole electric heating equipment for the horizontal well, in yuan; E represents the electricity consumed by the electric heating equipment during oil well production, in kW·h. Electricity cost, yuan; The price is for oil, in yuan.

[0025] Establish a two-dimensional curve chart showing the relationship between the main influencing parameters and the percentage increase in oil production and the input-output ratio; S6. On the two-dimensional curve chart, based on the geological reservoir and production parameters of the target well, find the corresponding percentage increase in oil production and the input-output ratio, and determine the evaluation indicators of the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells.

[0026] The present invention will now be described in detail with reference to the accompanying drawings and embodiments.

[0027] It should be noted that, unless otherwise specified, the embodiments and features described in the present invention can be combined with each other.

[0028] Example 1 The Bohai S oilfield is a layered reservoir with well-developed layers, good connectivity, and favorable physical properties (average permeability of 2815 mD and average porosity of 32%). The oilfield is developed using water injection, with a relatively complete injection-production well network, resulting in stable production and a relatively slow rate of water cut increase and production decline. Due to the high asphaltene content and viscosity of the crude oil (24.1 mPa·s to 452.0 mPa·s underground), some wells face significant lift challenges and require additional fluid for production. To improve well production and lift efficiency, well C will be selected for horizontal well downhole electric heating. The potential for increased oil production and the cost-benefit ratio of electric heating in this well need to be predicted to provide a basis for scheme design and effect evaluation.

[0029] S1 was used to obtain geological reservoir parameters (porosity, permeability, reservoir pressure, reservoir temperature), rock-fluid thermal properties (specific heat and thermal conductivity of rocks, density, viscosity, specific heat and thermal conductivity of crude oil, density, viscosity, specific heat and thermal conductivity of water), and well parameters for horizontal wells with downhole electric heating (horizontal section length, well logging interpretation data, viscosity analysis data from wellhead sampling, production rate, and water cut). Specific data are shown in Table 1.

[0030] Table 1. Details of S Oilfield Collection Parameters S2 utilizes an improved horizontal wellbore-reservoir heat transfer simulation device to conduct a physical simulation experiment of downhole electric heating in a horizontal well under a formation temperature and pressure system. Through similarity criterion calculations, actual heating time, permeability, crude oil viscosity, production rate, and heating power parameters are converted into parameters under experimental conditions.

[0031] To simulate the formation fluid supply during horizontal well production, fluid needs to be replenished to the sand-filled model through an injection point in the middle of the outer wall of the sand-filled model container. The method for determining the replenishment volume is as follows: when the production rate of the horizontal well at the field scale is 100m³ / s... 3 At / d, the production rate, converted to formation conditions using the similarity criterion, was 138 ml / min, and the replenishment rate to the sand-filled model through the eight inner wall injection points was 17.25 ml / min. The experimental parameters are shown in Table 2.

[0032] Table 2 Parameters of Physical Simulation Experiment for Downhole Electric Heating in Horizontal Wells The experimental procedure for the physical simulation of downhole electric heating in horizontal wells under the formation temperature and pressure system (S3) includes four parts: experimental preparation, model sand filling, establishment of initial saturation, and electric heating production.

[0033] Experimental preparation: First, test the experimental equipment, then prepare the heavy oil sample required for the experiment, and prepare quartz sand of the appropriate particle size; Model sand filling: Use wet filling method to fill the sand filling cylinder with the required mesh size of quartz sand for the corresponding experiment, place the horizontal pipe and resistance heater and connect the wires, tighten and seal, and then connect the injection and extraction pipelines; Establish initial pressure, saturation, and temperature fields: Simulate the original formation pressure by adjusting the back pressure valve, establish the initial oil-water saturation by using the oil-water mixed injection method, and establish the original formation temperature by turning on the thermal compensation insulation jacket; Once the initial pressure, saturation, and temperature fields of the sand-filled model reach the corresponding experimental values ​​and stabilize, the experiment can begin. Electric heating production: Adjust the heating power of the cable heater to the value corresponding to the experimental parameters, control the liquid production rate with the back pressure valve, and adjust the injection rate of the liquid injection point in the middle of the inner wall of the sand filling model to the value corresponding to the experimental parameters. Thermocouples collect the internal temperature data of the sand filling model and transmit it to the computer temperature measurement program. Record the temperature and energy consumption data of the experiment throughout the process. Temperature field distribution near the well during the well shut-in and preheating stage is as follows: Figure 3 As shown, the temperature field distribution in the near-wellbore zone during the production stage is as follows: Figure 4 As shown, physical simulation experiments clarified the distribution law of near-well reservoir temperature field during well shut-in preheating and simultaneous production and heating: during the well shut-in preheating stage, the heating range of the near-well zone of the horizontal well under downhole electric heating is approximately ellipsoidal, and the overall heating range is large; during the production stage, the heating range is large at the heel and low at the toe, approximately willow leaf-shaped, and the overall temperature rise and heating range are smaller than those during the well shut-in preheating stage.

[0034] Reservoir fluid parameters affecting temperature field distribution include permeability and crude oil viscosity. As reservoir permeability increases, the maximum heating temperature and effective heating radius of electric heating gradually decrease; conversely, as crude oil viscosity increases, the effective heating radius of electric heating gradually decreases, while the maximum heating temperature increases. Oil well production parameters that affect the temperature field distribution include production rate and water cut. As water cut and production rate increase, the heating amplitude and effective heating range of electric heating gradually decrease, and the uneven heating at the heel and toe ends intensifies.

[0035] S4. A numerical model at the wellbore level for typical wells was established based on the geological and reservoir parameters of the S oilfield. The mesh in the near-wellbore area was finely refined (mesh size to 0.5m). The CMG software was used to simulate the complex tubing structure inside the screen and the horizontal section where the heating cable was bundled with the tubing. This model was used to simulate the changes in oil production before and after the implementation of downhole electric heating in the horizontal well, and the cumulative oil production was calculated to determine the increase in oil production before and after electric heating. Based on the actual conditions of the target oilfield, 3 to 4 variation levels were selected for the reservoir fluid parameters and well parameters affecting the heating conditions. Specifically, the permeability values ​​were 1000mD, 2000mD, and 4000mD; the crude oil viscosity values ​​were 350mPa·s, 1000mPa·s, and 2000mPa·s; and the initial production rate was 50m³ / s. 3 / d、100m 3 / d、200m 3 / d, with water cut values ​​of 0%, 30%, 60%, and 90%. Cumulative oil production variations were simulated for each value, and the increase in oil production was calculated. A multifactor ANOVA was used to conduct a sensitivity analysis of the effects of these parameters on the increase in oil production. The results showed that the sensitivity to the increase in oil production was ranked as follows: water cut > production rate > crude oil viscosity > permeability. Therefore, changes in water cut and production rate have the greatest impact on the increase in oil production.

[0036] S5. Combining the statistical data on electricity consumption, liquid production, oil production, and water content, and based on the formulas for calculating the percentage increase in oil production and the input-output ratio, the percentage increase in oil production and the corresponding input-output ratio for different schemes are calculated. The cost of the cable heating equipment is approximately 2 million yuan, the electricity cost is 0.5 yuan / kW·h, and the oil price is 50 US dollars / barrel. The simulation data and calculation results are shown in Table 3.

[0037] Table 3 Numerical simulation results and calculation results for different influencing parameters like Figure 5 and Figure 6 As shown, a two-dimensional curve chart is established to illustrate the relationship between permeability, crude oil viscosity, production rate, water content, percentage increase in oil yield, and input-output ratio; Figure 5 It can be seen that the production rate and water content have a significant impact on the production increase effect; as the production rate and water content increase, the percentage increase in oil yield decreases. In contrast, crude oil viscosity and permeability have relatively smaller effects on the percentage increase in oil yield and the output-input ratio; specifically, as crude oil viscosity increases, the percentage increase in oil yield rises; as permeability increases, the percentage increase in oil yield decreases. Figure 6 It can be seen that the input-output ratio increases with the increase of production rate and water content. The input-output ratio decreases with the increase of crude oil viscosity, and increases with the increase of permeability.

[0038] S6. According to the two-dimensional chart, when the oil well permeability is 2000 mD, the crude oil viscosity is 350 mPa·s, and the production rate is 100 m / s... 3 / d, when the moisture content is 30%, from Figure 5 It can be seen that the percentage increase in oil content is 25.8%, from... Figure 6 It can be seen that the input-output ratio is 0.217; when the oil well permeability is 4000 mD, the crude oil viscosity is 350 mPa·s, and the production rate is 100 m / s. 3 / d, when the moisture content is 30%, from Figure 5 It can be seen that the percentage increase in oil content is 25.2%, from Figure 6 It can be seen that the input-output ratio is 0.219; when the oil well permeability is 2000 mD, the crude oil viscosity is 1000 mPa·s, and the production rate is 100 m / s. 3 / d, when the moisture content is 30%, from Figure 5 It can be seen that the percentage increase in oil content is 26.6%, from... Figure 6 It can be seen that the input-output ratio is 0.210; when the oil well permeability is 4000 mD, the crude oil viscosity is 1000 mPa·s, and the production rate is 100 m / s. 3 / d, when the moisture content is 30%, from Figure 5 It can be seen that the percentage increase in oil content is 26.5%, from... Figure 6 It can be seen that the input-output ratio is 0.214. Well C has a permeability of 2500 mD, crude oil viscosity of 385 mPa·s, and a cold production rate of 100 m³ / s. 3 / d, with a water content of 30%. Both the cold-production liquid rate and water content can be maintained at [value missing]. Figure 5 , Figure 6 The results show that, given the permeability is between 2000mD and 4000mD and the crude oil viscosity is between 350mPa·s and 1000mPa·s, and combining the results of permeability of 2000mD and 4000mD and crude oil viscosity of 350mPa·s and 1000mPa·s, the estimated percentage increase in oil production after three years of electric heating in this well is approximately 25.2% to 26.6%, with an input-output ratio of approximately 0.210 to 0.219.

[0039] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present invention should be included within the scope of protection of the present invention. Furthermore, the present invention is not limited to the applications listed in the specification and embodiments; it can be applied to various fields suitable for the present invention. For those skilled in the art, other modifications can be easily implemented. Therefore, without departing from the general concept defined by the claims and their equivalents, the present invention is not limited to the specific details and examples shown and described herein.

Claims

1. A rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells, characterized in that, Includes the following steps: S1. Collect geological reservoir parameters, rock fluid thermal properties, temperature and pressure monitoring data of the target oilfield, as well as parameters of the oil wells where downhole electric heating of horizontal wells is implemented; S2. Improve the horizontal wellbore-reservoir heat transfer simulation device; add an injection point in the middle of the inner wall of the cylindrical sand-filled cylinder of the simulation device to simulate the near-well reservoir fluid supply under actual formation temperature and pressure conditions with downhole electric heating in horizontal wells. S3. Using an improved simulation device, conduct a physical simulation experiment of downhole electric heating in horizontal wells under the formation temperature and pressure system of the target oilfield, simulate the near-well reservoir heating field distribution, and determine the influence of reservoir fluid parameters and well parameters on the heating conditions. S4. Based on experimental understanding, establish a numerical simulation of typical well reservoirs at the wellbore level, study the changes in heating power, temperature and production capacity during horizontal well electric heating, and conduct sensitivity analysis on reservoir fluid parameters and well parameters that affect the heating conditions. S5. Statistical simulation results, inputting economic parameters such as equipment cost, electricity cost and oil price, calculate the percentage increase in oil production and the input-output ratio of horizontal well electric heating; establish two-dimensional curves showing the relationship between the influencing parameters and the percentage increase in oil production and the input-output ratio. S6. On the two-dimensional curve chart, based on the geological reservoir and production parameters of the target well, find the corresponding percentage increase in oil production and the input-output ratio, and determine the evaluation indicators of the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells.

2. The rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells according to claim 1, characterized in that, Step S1 includes: Based on actual drilling and testing, the geological reservoir parameters of the target oilfield were statistically analyzed, including porosity, permeability, reservoir pressure, and reservoir temperature. Based on analytical test results, the rock-fluid thermal properties of the target oilfield were statistically analyzed, including the specific heat and thermal conductivity of rocks, the density, viscosity, specific heat and thermal conductivity of crude oil, and the density, viscosity, specific heat and thermal conductivity of water. The well parameters of the target oil wells were also statistically analyzed, including the horizontal section length, production rate, and water cut.

3. The rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells according to claim 1, characterized in that, Step S2 includes: simulating the reservoir rock structure by filling the sand-filling cylinder with sand; placing a horizontal pipe at the center of the sand-filling cylinder to simulate a horizontal wellbore, the horizontal pipe being connected to the production system to simulate horizontal well production; fixing a resistance heater outside the horizontal pipe to simulate a heating cable, the resistance heater having a heating power of 0~1.5kW / m and a heating temperature of 0~500℃; uniformly deploying 30 thermocouples inside the sand-filling model to collect temperature data; and setting a thermal compensation insulating sleeve outside the sand-filling cylinder, the thermal compensation insulating sleeve having both heating and insulation functions, the heating temperature of the thermal compensation insulating sleeve being 0~500℃, used to establish the initial reservoir temperature and to insulate the sand-filling model. The core component of the simulation device, the cylindrical sand-filling cylinder, was modified. Eight liquid injection points were evenly deployed in the middle of the inner wall of the cylindrical sand-filling cylinder along the circular tangent to inject oil-water mixture into the sand-filling model. The injection rate was 0~300ml / min, which can simulate the near-well reservoir fluid supply state of horizontal wells under exhaustion or stable displacement conditions.

4. The rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells according to claim 1, characterized in that: In step S3, the physical simulation experiment process of downhole electric heating in horizontal wells under the formation temperature and pressure system includes experimental preparation, model sand filling, establishment of initial pressure, saturation and temperature fields, and electric heating production. The model sand filling process includes: using a wet filling method to fill the sand filling cylinder with the required mesh size of quartz sand for the experiment, placing the horizontal pipe and resistance heater and connecting the wires, tightening and sealing, and then connecting the injection and extraction pipelines. Establishing the initial pressure, saturation, and temperature fields includes: simulating the original formation pressure by adjusting the back pressure valve, establishing the initial oil-water saturation using an oil-water mixed injection method, and establishing the original formation temperature by activating the thermal compensation insulation jacket; once the initial pressure, saturation, and temperature fields of the sand-filled model reach the required experimental values ​​and stabilize, the experiment can begin. The electric heating production process includes: adjusting the heating power of the cable heater to the value corresponding to the experimental parameters, controlling the liquid production rate with a back pressure valve, adjusting the injection rate of the liquid injection point in the middle of the inner wall of the sand-filled model to the value corresponding to the experimental parameters, collecting the temperature data inside the sand-filled model through thermocouples and transmitting it to the computer temperature measurement program, and recording the temperature and energy consumption data of the experiment throughout the process. After the experiment, turn off the cable heater, open the compensation sleeve, and cool the sand-filled model. The temperature data collected by the computer temperature measurement program is analyzed. Based on the temperature distribution characteristics of the wellbore and near-well reservoir during downhole electric heating of horizontal wells, the distribution law of the heating field is derived, and the influence of reservoir fluid parameters and well parameters on the heating field distribution is qualitatively analyzed.

5. The rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells according to claim 1, characterized in that, Step S4 includes: combining the heating field distribution pattern obtained from experiments, as well as the affected reservoir fluid parameters and well parameters, to establish a numerical model at the wellbore level for typical wells based on the target oilfield parameters. This numerical model includes wellbore simulation based on the actual well completion structure and in-depth description of the near-well reservoir. Using this numerical model, the changes in oil production before and after the implementation of downhole electric heating in horizontal wells can be simulated, and the cumulative oil production can be statistically analyzed to calculate the increase in oil production before and after electric heating. Based on the actual situation of the target oilfield, 3 to 4 levels of change are selected for the reservoir fluid parameters and well parameters that affect the heating status, respectively, to simulate the changes in cumulative oil production and calculate the increase in oil production. Sensitivity analysis of the influencing parameters on the increase in oil production is carried out.

6. The rapid method for evaluating the production enhancement effect and economic efficiency of downhole electric heating in horizontal wells according to claim 1, characterized in that: In step S5, the percentage increase in oil production over three years and the input-output ratio are used as indicators for evaluating the production increase effect and economic efficiency, respectively; the formula for calculating the percentage increase in oil production is as follows: （1） In the formula, M represents the percentage increase in oil consumption, %; The cumulative oil production over three years of cold extraction development is [amount missing]. The cumulative oil production over three years using downhole electric heating in horizontal wells under the same production system is calculated in square meters. The formula for calculating the input-output ratio is as follows: （2） In the formula, IOR is the input-output ratio; E represents the cost of the downhole electric heating equipment for the horizontal well, in yuan; E represents the electricity consumed by the electric heating equipment during oil well production, in kW·h. Electricity cost, yuan; The price is for oil, in yuan.

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