Method for determining retention temperature prediction model of high-water-content thickened oil

Abstract

The invention discloses a method for determining a retention temperature prediction model of high-water-content thickened oil. The method comprises the following steps: step 1, calibrating experimental equipment; step 2, taking an oil sample after dehydration of field thickened oil, and preparing an oil-water emulsion; 3, preheating an oil sample, a water sample and a device; step 4, loading a sample, and starting a pumping system; step 5, according to experiment requirements, running for a certain time to reach a stable state, and then adjusting the temperature to carry out a cooling experiment; 6, monitoring changes of temperature and pressure in real time, and sampling under a stable condition; if the pressure of the test section continuously rises or fluctuates greatly, the cooling experiment is stopped; and 7, establishing a high-water-content thickened oil viscous flow temperature prediction model. The high-water-content thickened oil gathering and transportation boundary condition obtained through the method can be popularized and applied to the actual pipeline gathering and transportation process, safe operation of a pipeline can be guaranteed, energy consumption can be reduced to a great extent, and the method is safe, reliable and remarkable in application effect.

Description

Technical Field

[0001] This invention relates to a method for determining a prediction model for the retention temperature of heavy oil with high water content, belonging to the field of safety operation evaluation of heavy oil cryogenic gathering and transportation pipelines. Background Technology

[0002] In recent years, most oilfields in my country have entered the high water-cut oil production stage, with the comprehensive water cut of the oil samples collected on-site reaching over 70%. As the water cut continues to increase, the heat loss of the gathering and transportation system increases. However, on the other hand, the fluidity of heavy oil in the pipeline also improves with the increase in water cut. But due to the high viscosity and temperature sensitivity of heavy oil, it is difficult to determine the temperature boundary of the gathering and transportation pipeline by relying solely on on-site experience during the gathering and transportation of high water-cut heavy oil. This leads to pipe blockage or high energy consumption during the gathering and transportation process. The main problem is the lack of criteria for judging the boundary conditions of gathering and transportation of high water-cut heavy oil. Summary of the Invention

[0003] The purpose of this invention is to provide a method for determining the retention temperature prediction model of high water content heavy oil. The flow pattern of high water content heavy oil simulated by this method has the same fluid dynamic change characteristics as the flow pattern of the pipeline in the field, indicating that the high water content heavy oil configured in the experiment is consistent with the emulsification conditions of high water content heavy oil in the pipeline in the field, and the cooling process of the pipeline in the field can be simulated in the indoor experiment.

[0004] To achieve the above objectives, the technical solution adopted by the present invention is: a method for determining a prediction model for the retention temperature of heavy oil with high water content, comprising the following steps:

[0005] Step 1, Experimental Equipment Calibration: The existing loop device is used for the experiment. Before the experiment, it is calibrated to ensure the flow rate of the loop device and the accuracy of the instrument.

[0006] Step 2: Take a sample of the dehydrated heavy oil from the site and prepare an oil-water emulsion;

[0007] Step 3: Place the prepared oil-water sample into a constant temperature water bath to ensure a constant temperature and preheat the mixing tank and pipelines.

[0008] Step 4, preparation of experimental samples and start-up of experimental equipment: After the oil-water sample and pipeline temperature reach the set temperature and stabilize, take samples according to a certain ratio and pour them into the mixing tank; then, start the stirring motor and pumping system to circulate the oil-water mixture.

[0009] Step 5: Run the test for a certain period of time to reach a stable state, and then adjust the temperature to conduct a cooling experiment. During this experiment, measure the liquid water content regularly and replenish oil and water samples to maintain stability.

[0010] Step 6: Monitor temperature and pressure changes in real time and take samples under stable conditions; if the pressure in the test section continues to rise or fluctuates greatly, stop the cooling experiment.

[0011] Step 7: Based on the results of the above indoor loop experiments, analyze the different influencing factors of the stagnation temperature of high water content heavy oil, and finally establish a prediction model for the stagnation temperature of high water content heavy oil.

[0012] Furthermore, in step one, calibration includes cleaning residues in the loop and setting the flow meter, temperature difference, and pressure difference sensors to zero to reduce system errors.

[0013] Furthermore, in step two, the preparation of the oil-water emulsion includes:

[0014] a) Set the temperature of the temperature-controlled water bath to different field temperatures: 80℃, 70℃ and 60℃. Based on the emulsion viscosity and emulsion water content of the produced fluid at the wellhead, take the dehydrated heavy oil and deionized water into a 500mL beaker, prepare a mixture with different water contents, and put it into a constant temperature water bath for preheating for 30min.

[0015] b) Turn on the agitator of the four-blade paddle rotor system and set the stirring speed to 1000 r / min; use the agitator to prepare the oil-water emulsion for the indoor experiment, and uniformly use 500 mL beakers, set the stirring time to 20 min, and the speed to 1000 r / min, to ensure that the preparation temperature is consistent with the wellhead produced fluid temperature.

[0016] Furthermore, viscosity tests were conducted on different oil samples and their emulsions at different temperatures.

[0017] Furthermore, the loop device is also equipped with two large TSAA temperature-controlled water baths, which use a data monitoring system to precisely control the temperature of the entire pipeline, record data in real time, and the temperature controllable range is 0 to 90℃ with an accuracy of ±0.01℃. At the same time, the loop device is also equipped with a medium-sized peristaltic pump, which adjusts the speed of the peristaltic pump to make the oil-water mixture reach the set flow rate, and simulates the actual flow rate in the pipeline in the room.

[0018] Furthermore, the agitation system of the ring device employs a spiral agitator.

[0019] Furthermore, in steps three and four, 6L of oil-water mixtures with water contents of 70%, 80%, 90%, and 95% are prepared, placed in a tank for pretreatment at 80°C, and the loop pipeline is preheated. Then, the prepared oil-water mixtures are poured into a mixing tank, the mixing speed is set to 500 r / min, and the pumping system is turned on.

[0020] Furthermore, in step six, the temperature point where the pressure drop increases by 50% or more during the cooling process is set as the low-temperature gathering and transportation temperature boundary and stagnation temperature for high water content heavy oil.

[0021] Furthermore, in step seven, experiments are conducted on different heavy oil samples to test pressure drop data at different water contents, flow rates, and temperatures. The stagnation temperature is determined by observing the point of sudden increase in pressure drop, serving as the basis for judging the boundary conditions of gathering and transportation. The stagnation temperature data obtained in the experiment are organized into a structured dataset, clarifying the range of each parameter, wherein the shear stress is converted through the flow rate.

[0022] Furthermore, in step seven, a correlation analysis is performed on the influencing factors: the moisture content is determined to be the factor affecting the stagnation temperature. Shear stress τ and oil viscosity μ were used, with viscosity showing a repetitive correlation with shear stress. Water content and shear stress were selected as independent variables. Finally, based on experimental data, a nonlinear regression method was used to construct a stagnation temperature model.

[0023] The present invention has the following features and effects:

[0024] (1) The boundary of low-temperature gathering and transportation of heavy oil with high water content was studied for the first time through indoor loop experiments, and the definition of "stagnant temperature" was proposed.

[0025] (2) The water bath system was used to achieve precise temperature control of the entire experimental setup, with a temperature control range of 0-100℃;

[0026] (3) Using a data acquisition system, the temperature and pressure of the test pipe section are detected in real time. The differential pressure test range is -62.2 to 62.2 kPa, and the accuracy is ±0.04%.

[0027] (4) By adjusting the oil pump frequency, the oil flow rate in the pipe can be changed, so that the shear rate in the loop is consistent with that in the actual pipeline, thereby obtaining simulation results that are closer to the actual pipeline on site.

[0028] (5) Record the real-time observation of the fluid flow pattern inside the pipe through the glass observation pipe section using video recording, and analyze the observation.

[0029] (6) The indoor loop test can fully simulate the field test and obtain field test verification;

[0030] (7) By adjusting the frequency of the gear oil pump, the flow rate of the oil in the pipe can be changed, so that the shear rate in the loop can be kept consistent with the actual pipeline, thereby obtaining simulation results that are closer to the actual pipeline on site.

[0031] (8) After the experiment, the rise in water bath temperature caused the solidified oil adhering to the inner wall of the pipe to fall off and melt. In addition, the two purging devices purged the entire pipeline, thoroughly removing the residual oil and water in the pipeline, preventing the pipeline from corroding and rusting, which would affect subsequent experiments.

[0032] (9) A temperature boundary prediction model for gathering and transportation of heavy oil with high water content was established.

[0033] In summary, this invention simulates the flow state of high water-content heavy oil under different water contents, viscosities, and shear rates, analyzes the flow morphology of high water-content heavy oil under different conditions, lays the foundation for determining the "stagnant flow temperature" of high water-content heavy oil, and proposes a model method for determining the stagnant flow temperature, providing theoretical guidance for actual field conditions. Attached Figure Description

[0034] Figure 1 This is the viscosity-temperature curve of crude oil #1;

[0035] Figure 2 This is a schematic diagram of an indoor loop system;

[0036] Figure 3 It is a spiral stirring paddle;

[0037] Figure 4 It shows the pressure drop change of oil sample #1 at a water content of 70% and a flow rate of 0.19 m / s (folding blade).

[0038] Figure 5 The pressure drop change of oil sample #1 at a water content of 70% and a flow rate of 0.19 m / s (using a helical impeller);

[0039] Figure 6 These are the results of the cooling experiment on heavy oil sample #1;

[0040] Figure 7 This is the pressure drop curve of the test section during the cooling process of oil sample #1 (70% - 0.45 m / s);

[0041] Figure 8 It is the temperature boundary for gathering and transporting heavy oil with high water content;

[0042] Figure 9 This shows the variation of the stagnation temperature of heavy oil sample #1 with water content (0.19 m / s);

[0043] Figure 10 This is the relationship between the stagnation temperature and shear stress of the No. 1 heavy oil sample.

[0044] Figure 11 It is a parameter correlation analysis. Detailed Implementation

[0045] The present invention will now be described in detail with reference to the accompanying drawings and specific embodiments.

[0046] A method for determining a prediction model for the retention temperature of heavy oil with high water content, the method comprising the following steps:

[0047] Step one: Calibrate the experimental equipment to ensure the flow rate and instrument accuracy of the loop device. This includes cleaning any residue from the loop and zeroing the flow meter, temperature differential, and pressure differential sensors to reduce system errors.

[0048] Step two: Prepare an oil-water emulsion. Based on the characteristics of the extracted fluid, prepare the required oil-water emulsion in a container of uniform specifications using a stirring device, with specific stirring time, speed and temperature.

[0049] Step 3: Place the prepared oil-water sample into a constant temperature water bath to ensure a constant temperature and preheat the mixing tank and pipeline.

[0050] Step four: Sample preparation and equipment startup. Once the oil-water sample and pipeline temperatures have reached the set temperature and stabilized, take samples according to a specific ratio and pour them into the mixing tank. Then, start the stirring motor and pumping system to circulate the oil-water mixture.

[0051] Step five: Run the experiment for a certain period of time to reach a stable state, then adjust the temperature to conduct a cooling experiment. During the experiment, periodically measure the liquid water content and replenish oil and water samples to maintain stability.

[0052] Step six requires real-time monitoring of temperature and pressure changes, and sampling under stable conditions. If the pressure in the test section continues to rise or fluctuates significantly, the cooling experiment should be stopped.

[0053] Step 7: After completing the experiment, clean the system to ensure that any residual liquid is removed.

[0054] Step 8: Experiments were conducted on four heavy oil samples to test pressure drop data under different water contents, flow velocities, and temperatures. The "stagnant temperature" was determined by observing the point of sudden increase in pressure drop, serving as the basis for judging the gathering and transportation boundary conditions. The stagnant temperature data obtained in the experiments (covering different oil samples, water contents, and flow velocities) were organized into a structured dataset, clarifying the range of each parameter, with shear stress converted from flow velocity.

[0055] Step 9: Conduct correlation analysis on influencing factors: determine that the main factor affecting the stagnation temperature is moisture content. Shear stress (τ) and oil viscosity (μ) were used as independent variables, with viscosity showing a repetitive correlation with shear stress. Finally, water content and shear stress were selected as independent variables.

[0056] Step 10: Model building and parameter fitting: Based on experimental data, a nonlinear regression method is used to construct a stagnation temperature model.

[0057] The following examples will provide further details:

[0058] 1) Preparation of oil-water emulsion

[0059] a) Set the temperature of the temperature-controlled water bath to different field temperatures (80℃, 70℃ and 60℃). Based on the emulsion viscosity and emulsion water content of the produced fluid at the wellhead, take the dehydrated heavy oil and deionized water into a 500mL beaker, prepare a mixture with different water contents, and put it into a constant temperature water bath for preheating for 30min.

[0060] b) Turn on the agitator of the four-blade paddle rotor system and set the agitation speed to 1000 r / min;

[0061] Oil-water emulsions used in the laboratory experiments were prepared using a stirring device. 500mL beakers were consistently used, with a stirring time of 20 minutes and a stirring speed of 1000 rpm, ensuring the preparation temperature matched the wellhead produced fluid temperature. Taking oil sample #1 as an example, viscosity tests were conducted on oil sample #1 and its emulsion at different temperatures. The test results are as follows: Figure 1 As shown.

[0062] 2) Indoor circular track experimental setup

[0063] (a) The indoor loop experimental apparatus used in this embodiment mainly consists of a stirring system, a peristaltic pump, metering equipment, a purging system, a data monitoring system, a flow pattern observation section, and a test section. Figure 2 This is a schematic diagram of the experimental setup.

[0064] The indoor circular experimental setup is equipped with a 20L circulating mixing tank. Considering the density difference between the high viscosity of heavy oil and the deionized water, a helical impeller is used in this experiment. Figure 3 As shown, the stirring speed is adjustable, providing a high rotational speed during stirring to ensure thorough circulation and mixing of the oil and water phases. Furthermore, the shear force prevents excessive emulsification of the oil and water phases. By adjusting the speed, the shearing action of the formation is simulated, ensuring that the experimental environment remains consistent with actual field conditions. The indoor loop experiment is equipped with two large TSAA temperature-controlled water baths, which can precisely control the temperature of the entire pipeline (including the test section) through a data monitoring system, recording data in real time. The temperature controllable range is 0–90℃, with an accuracy of ±0.01℃. Simultaneously, the loop system is equipped with a medium-sized peristaltic pump. By adjusting the pump speed, the oil-water mixture can reach a set flow rate, simulating the actual flow velocity in the field pipeline. In this experiment, the test section is 90mm long with an inner diameter of 29mm. The data acquisition system can monitor the pressure drop data of the test section in real time and conduct exploratory experiments based on the changes in pressure drop during cooling and the changes in flow pattern in the observation section.

[0065] (b) Spiral agitator

[0066] In the stirred tank experiment used to investigate the temperature boundary conditions of high water- and waxy crude oil gathering and transportation, a 4-bladed, 45° folded-blade impeller with a diameter of 60 mm is generally used. Taking oil sample #1 with a water content of 70% and a flow velocity of 0.19 m / s as an example, after applying the folded-blade impeller to the indoor loop test device, it was found that the pressure drop did not show a significant trend as the temperature continued to decrease. Figure 4 As shown. This is because there is a density difference between oil and water. After passing through the ring test, the oil phase has a lower density than the water phase, making it difficult for the oil phase to mix evenly with the water phase in the mixing tank. As a result, the oil phase re-enters the ring for circulation, leading to the ring being mainly composed of the water phase.

[0067] Therefore, this embodiment uses a helical impeller. The helical impeller ensures uniform mixing of the aqueous and oil phases. The oil-water mixture simultaneously enters the annular channel, and a significant pressure surge occurs as the temperature decreases. Figure 5 As shown.

[0068] 3) Examples of oil and water samples, as well as equipment preheating and sample loading

[0069] Oil-water mixture preparation. Based on the actual pipeline conditions on site, prepare 6L of oil-water mixtures with different water contents (70%, 80%, 90%, and 95%), place them in a tank for 80℃ pretreatment, and preheat the loop pipeline. Pour the prepared oil-water mixture into the tank, set the spiral agitator speed to 500r / min, and start the pumping system.

[0070] 4) Example of determining the residence temperature using a ring cooling experiment

[0071] Oil samples (#1) were used to prepare oil-water mixtures with different water contents of 70%, 80%, 90%, and 95%. The flow velocities of the mixtures were set to 0.19 m / s, 0.32 m / s, and 0.45 m / s, respectively. The experimental results are as follows: Figure 6 As shown. Temperatures where the pressure drop increases by 50% or more during the cooling process are defined as the low-temperature gathering and transportation temperature boundary for high-water-content heavy oil, i.e., the "stagnant temperature," such as... Figure 8 As shown, when the temperature drops below the "stagnant temperature", a large amount of gelled oil clumps accumulate in the pipe, forming gelled oil blocks, which causes a sharp decrease in the pipe flow area and a sudden increase in pressure, seriously hindering the gathering and transportation of heavy oil with high water content.

[0072] Through indoor loop experiments, the changes in flow patterns of heavy oil under different water contents, flow velocities, and temperatures were analyzed, and five flow patterns were summarized: stratified flow pattern, oil-water emulsion and aqueous phase intermittent flow pattern, oil-water emulsion dispersed flow pattern, oil-water emulsion slug and aqueous phase intermittent flow pattern, and gelled oil agglomerate slug and aqueous phase intermittent flow pattern. It was also found that when the oil-water two-phase flow pattern transitioned from the oil-water emulsion slug and aqueous phase intermittent flow pattern to the gelled oil agglomerate slug and aqueous phase intermittent flow pattern, the pressure drop in the test section showed a significant change, with an increase of more than 50%.

[0073] Taking oil sample #1 as an example, under pipe flow conditions of 70% water content and 0.45 m / s, the trends of flow pattern and pressure drop in oil sample #1 are as follows: Figure 7 As shown, it was found that during the transition from the oil-water emulsion slug and intermittent aqueous flow pattern to the gelled oil agglomerate slug and intermittent aqueous flow pattern, the pressure suddenly increased from 0.65 kPa to 1.21 kPa, an increase of 86.1%.

[0074] Therefore, the stagnation temperature of oil sample #1 at different temperatures is shown in Table 1:

[0075] Table 1. Low-temperature gathering and stagnation temperature of high water-content heavy oil under different flow conditions

[0076]

[0077]

[0078] 5) Determination of the stagnation temperature model for heavy oil with high water content

[0079] Taking heavy oil sample #1 at a flow velocity of 0.19 m / s as an example, its stagnation temperature at 70%, 80%, 90%, and 95% was tested through an indoor loop test. The experimental results are as follows: Figure 9 As shown, as the water content increased from 70% to 95%, the stagnation temperature of the No. 1 heavy oil sample decreased from 28℃ to 23℃.

[0080] The reason for this is that as the water content increases, the probability of oil droplets colliding with the pipe wall decreases significantly, and the probability of collisions between oil droplets also decreases, making it difficult for oil droplets to spread rapidly within the pipe. This slows down the formation of the adhesion layer, resulting in a decreasing trend in stagnant temperature as the water content increases.

[0081] In actual pipelines, under the same water content, the flow velocity often determines whether gelled oil clumps can be washed away. In gathering and transportation pipelines, the fluid inside the pipe is mostly in a laminar flow state. Therefore, different flow velocities are converted into corresponding shear stresses to explore the influence of different shear stresses on the laminar flow temperature.

[0082] τ=μ×γ (Equation 1)

[0083]

[0084] In the formula, τ is the shear stress, Pa; μ is the viscosity of the oil-water two-phase system, Pa·s; γ is the shear rate, s⁻¹; v is the flow velocity, m / s; and D is the pipe diameter, m.

[0085] The shear stresses corresponding to the stagnation temperature points of heavy oil sample #1 at different flow velocities (0.19 m / s, 0.32 m / s, and 0.45 m / s) with water content ranging from 70% to 95% were compared. The experimental results are as follows: Figure 10 As shown.

[0086] Indoor loop experiments revealed that, for heavy oil sample #1 with a water content of 70-95%, the stagnation temperature decreased with increasing shear stress. This is because as the flow velocity increases within the pipe, the corresponding shear stress also increases, enhancing the scouring and stripping effect on the gelled oil clumps and adhered layers within the pipe. This makes it easier to break down the structure of the gelled oil clumps and adhered layers, slowing down the formation of the adhered layer. Therefore, the stagnation temperature decreases with increasing shear stress.

[0087] Based on the above experimental results, and combined with numerous other experimental findings, the flow velocity within the pipe was converted into different shear stresses. The main factors influencing the temperature boundary of low-temperature gathering and transportation of high-water-content heavy oil were determined to be water content and shear stress. Therefore, the relationship between the stagnation temperature and these influencing factors is shown below.

[0088]

[0089] In the formula, T 滞 The stagnation temperature is ℃. τ represents the moisture content, in wt%; τ represents the shear stress, in Pa.

[0090] First, plot a scatter plot of water content versus shear stress versus stagnation temperature of high water content heavy oil, such as... Figure 11 As shown, correlation detection was performed using SPSS software.

[0091] from Figure 11 The data shows a high correlation between moisture content, shear stress, and stagnation temperature. Considering both scatter plot distribution and SPSS data analysis, the order of influence of moisture content and shear stress on stagnation temperature is: shear stress > moisture content. Furthermore, both moisture content and shear stress are negatively correlated with stagnation temperature.

[0092] Table 2 Correlation Analysis of Influencing Factors

[0093]

[0094] Based on the results of indoor ring tunnel experiments, a nonlinear regression was performed on the temperature boundary model for low-temperature gathering and transportation of high water-cut heavy oil. The water cut in the experimental data ranged from 70% to 95%, and the shear stress ranged from 1.95 to 57.10 Pa. Substituting the experimental data into the unknowns in the obtained model, a prediction model for the temperature boundary of high water-cut heavy oil gathering and transportation was established as shown below.

[0095] T 滞 =1.483×10 3 φ -0.89 τ -0.114 (Equation 4)

[0096] The foregoing has shown and described the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the above embodiments do not limit the scope of protection of the present invention in any way, and all technical solutions obtained by equivalent substitution or other means fall within the scope of protection of the present invention. Parts not covered in this invention are the same as or can be implemented using existing technology.

Claims

1. A method for determining a prediction model for the retention temperature of heavy oil with high water content, characterized in that, Includes the following steps: Step 1, Experimental Equipment Calibration: The existing loop device is used for the experiment. Before the experiment, it is calibrated to ensure the flow rate of the loop device and the accuracy of the instrument. Step 2: Take a sample of the dehydrated heavy oil from the site and prepare an oil-water emulsion; Step 3: Place the prepared oil-water sample into a constant temperature water bath to ensure a constant temperature and preheat the mixing tank and pipelines. Step 4, preparation of experimental samples and start-up of experimental equipment: After the oil-water sample and pipeline temperature reach the set temperature and stabilize, take samples according to a certain ratio and pour them into the mixing tank; then, start the stirring motor and pumping system to circulate the oil-water mixture. Step 5: Run the test for a certain period of time to reach a stable state, and then adjust the temperature to conduct a cooling experiment. During this experiment, measure the liquid water content regularly and replenish oil and water samples to maintain stability. Step 6: Monitor temperature and pressure changes in real time and take samples under stable conditions; if the pressure in the test section continues to rise or fluctuates greatly, stop the cooling experiment. Step 7: Based on the results of the above indoor loop experiments, analyze the different influencing factors of the stagnation temperature of high water content heavy oil, and finally establish a prediction model for the stagnation temperature of high water content heavy oil.

2. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 1, characterized in that, In step one, calibration includes cleaning residues in the loop and setting the flow meter, temperature difference and pressure difference sensors to zero to reduce system error.

3. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 1, characterized in that, In step two, the preparation of the oil-water emulsion includes: a) Set the temperature of the temperature-controlled water bath to different field temperatures: 80℃, 70℃ and 60℃. Based on the emulsion viscosity and emulsion water content of the produced fluid at the wellhead, take the dehydrated heavy oil and deionized water into a 500mL beaker, prepare a mixture with different water contents, and put it into a constant temperature water bath for preheating for 30min. b) Turn on the agitator of the four-blade paddle rotor system and set the stirring speed to 1000 r / min; use the agitator to prepare the oil-water emulsion for the indoor experiment, and uniformly use 500 mL beakers, set the stirring time to 20 min, and the speed to 1000 r / min, to ensure that the preparation temperature is consistent with the wellhead produced fluid temperature.

4. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 3, characterized in that, Viscosity tests were conducted on different oil samples and their emulsions at different temperatures.

5. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 1, characterized in that, The loop device is also equipped with two large TSAA temperature-controlled water baths. The data monitoring system accurately controls the temperature of the entire pipeline and records data in real time. The temperature controllable range is 0 to 90℃ with an accuracy of ±0.01℃. The loop device is also equipped with a medium-sized peristaltic pump. By adjusting the speed of the peristaltic pump, the oil-water mixture can reach the set flow rate, and the actual flow rate in the pipeline can be simulated indoors.

6. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 1 or 5, characterized in that, The agitation system of the ring device uses a spiral agitator.

7. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 1, characterized in that, In steps three and four, 6L of oil-water mixtures with water contents of 70%, 80%, 90%, and 95% are prepared, placed in a tank for pretreatment at 80°C, and the loop pipeline is preheated. Then, the prepared oil-water mixtures are poured into a mixing tank, the mixing speed is set to 500 r / min, and the pumping system is turned on.

8. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 1, characterized in that, In step six, the temperature point where the pressure drop increases by 50% or more during the cooling process is set as the low-temperature gathering and transportation temperature boundary and stagnation temperature for high water content heavy oil.

9. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 1, characterized in that, In step seven, experiments are conducted on different heavy oil samples to test pressure drop data at different water contents, flow rates, and temperatures. The stagnation temperature is determined by observing the point of sudden increase in pressure drop, which serves as the basis for judging the boundary conditions of gathering and transportation. The stagnation temperature data obtained in the experiment are organized into a structured dataset to clarify the range of each parameter, wherein the shear stress is converted through the flow rate.

10. The method for determining the retention temperature prediction model for high water-content heavy oil according to claim 9, characterized in that, In step seven, a correlation analysis was performed on the influencing factors: the factors affecting the stagnation temperature were determined to be water content φ, shear stress τ, and oil viscosity μ. Among them, viscosity and shear stress showed repeated correlation, and water content and shear stress were selected as independent variables. Finally, based on the experimental data, a stagnation temperature model was constructed using a nonlinear regression method.

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