Method for evaluating cold damage of hypercoagulable heavy oil reservoir

Abstract

The invention belongs to the technical field of production-increasing oil production matching, and discloses a method for evaluating cold damage of a high-condensation heavy oil reservoir, which is characterized in that physical simulation and numerical simulation methods are utilized to analyze the cold damage degree and reversibility of the reservoir, the lowest temperature for avoiding cold damage and the temperature recovery time of the reservoir from quantitative and qualitative aspects; according to physical simulation, crude oil properties are determined through crude oil viscosity-temperature and wax precipitation experiments, then a rock core is used for carrying out a breakthrough pressure experiment to determine the occurrence temperature of reservoir cold damage, a starting pressure experiment is used for determining the lowest temperature for avoiding damage, and a relative permeability experiment is used for determining the influence degree of cold damage on the reservoir seepage capacity; the mercury injection experiment analyzes the influence of cold damage on the pore structure of the reservoir, and the two-dimensional nuclear magnetic experiment and the laser confocal experiment determine whether the cold damage is reversible or not and determine the reversible temperature; the recovery time required by the working solutions with different liquid amounts and different temperatures entering the stratum is analyzed through numerical simulation, and finally the purposes of reducing the development cost of the high pour-point oil reservoir and improving the development effect are achieved.

Description

Technical Field

[0001] The invention relates to the technical field of oil production supporting equipment for increasing production, and in particular to a method for evaluating cold damage of a high-porosity viscous oil reservoir. Background Art

[0002] High-pour-point viscous oil reservoirs are a vital resource for global economic development. According to 2019 statistics, the world's proven reserves of high-pour-point viscous oil were approximately 815 billion tons, accounting for 70% of the world's remaining oil reserves. High-pour-point viscous oil generally has high freezing points, high viscosity, and poor fluidity. In some areas, the high-pour-point viscous oil contains high levels of wax and asphalt colloids.

[0003] When ambient-temperature working fluid enters a high-viscosity oil reservoir, it causes the reservoir temperature to drop, significantly increasing crude oil viscosity and affecting seepage resistance. In severe cases, this can cause the precipitation of colloidal asphaltene and wax components in the crude oil, leading to irreversible organic blockage and reservoir cold damage, resulting in suboptimal development results. While using high-temperature working fluid for development can reduce crude oil viscosity and avoid reservoir cold damage, heating the working fluid is not only complex but also energy-intensive, increasing development costs. Especially during volume fracturing, it is difficult to heat thousands of cubic meters of fracturing fluid in a short period of time.

[0004] People have long discovered that increasing the temperature of the working fluid entering the well can improve the development effect of high-pour point viscous oil. At the same time, injecting cold working fluid into high-pour point viscous oil reservoirs can cause cold damage, and this phenomenon has been studied. The specific research is as follows:

[0005] Tian Nailin et al. (Tian Nailin, Feng Jiji, Ren Ying et al., Cold damage to high-wax and high-freezing-point oil reservoirs during early cold water injection [J], Journal of Petroleum University, 1997, 23; 1) described the phenomenon that the early injection of cold water caused the temperature of the oil layer to decrease, and the high-wax and high-freezing-point crude oil precipitated wax in the pores of the oil layer. The lower the temperature of the injected cold fluid, the more serious the cold damage.

[0006] Li Xiaoguang et al. (Li Xiaoguang, Chen Zhenyan, Hui Xuefeng et al., A Review of Exploration and Development Technologies of Heavy Oil and High Pour Point Oil in Liaohe Oilfield [J], Journal of Petroleum University, 2007, 28; 4) discussed the exploration and development history of heavy oil and high pour point oil, systematically summarized the exploration and development of heavy oil and high pour point oil in Liaohe Oilfield over the years, and analyzed the existing difficulties.

[0007] Nie Xiangrong et al. (Nie Xiangrong, Yang Shenglai, Numerical simulation of cold damage characteristics of high pour point oil reservoirs [J], Oil Test Drilling Technology, 2014, 42; 1) established a physical model and a mathematical model to describe the cold damage of high pour point oil reservoirs during water injection development, and performed numerical solutions.

[0008] Xu Zhengen et al. (Xu Zhengen, Xin Wenming, Liu Yu et al., CO2 flooding to water-gas alternating drive state and reservoir damage characteristics in high pour point oil reservoirs [J], Fault Block Oil and Gas Field, 2019, 26; 5) CO2 flooding and its water-gas alternating drive (WAG) development will lead to the deposition of wax in high pour point oil reservoirs. The damage to the reservoir caused by CO2 flooding to WAG immiscible drive mainly occurs in the middle section of the reservoir, with the highest permeability damage rate of 4.58%, while the damage to the reservoir caused by miscible drive occurs in the middle and back sections of the reservoir, with the highest permeability damage rate of 6.72%.

[0009] Liu Lifeng et al. (Liu Lifeng, Ran Qiquan, Wang Zhiping et al., Method and device for predicting cold damage to tight oil productivity caused by fracturing fluid, Patent No. CN 105550780A) provide a method and device for predicting cold damage to tight oil productivity caused by fracturing fluid, which can predict cold damage to tight oil productivity caused by fracturing fluid.

[0010] An analysis of existing research and patents shows that the research depth and technical system still need to be improved to address a series of issues, such as the inability to determine whether the damage is reversible, the degree of cold damage at different temperatures, and the minimum temperature to avoid cold damage to the reservoir. Summary of the Invention

[0011] The present invention aims to overcome the shortcomings of the existing technology and provides a low-damage fracturing fluid for high-viscosity viscous oil reservoir fracturing and reconstruction. The system utilizes hot water for on-site fluid preparation and fracturing construction, and has the advantages of convenient fluid preparation and construction, rapid swelling rate, good temperature resistance, good sand-carrying performance, thorough gel breaking, and good demulsification and drainage performance. Using this system to perform sand fracturing reconstruction on high-viscosity viscous oil reservoirs effectively avoids cold damage to the reservoir while significantly improving the conductivity of the fracture support. Furthermore, after the fracturing fluid breaks, it clears and prevents wax and improves the fluidity of crude oil, facilitating the flow of high-viscosity viscous oil in the reservoir through the support and filling layer to the wellbore, significantly improving the reservoir production increase effect.

[0012] This invention aims to overcome the shortcomings of existing technologies and provides a method for evaluating cold damage in high-pour point oil reservoirs. By combining experimental physical simulation with numerical simulation, this method quantitatively and qualitatively analyzes the extent of cold damage, its reversibility, the minimum temperature required to avoid cold damage, and the reservoir temperature recovery time. This method determines the optimal working fluid temperature for high-pour point oil reservoir development and the recovery time after low-temperature working fluid enters the reservoir, ultimately reducing development costs and improving development outcomes.

[0013] The overall technical solution of the present invention is as follows: Physical and numerical simulation methods are used to quantitatively and qualitatively analyze the extent of reservoir cold damage, its reversibility, the minimum temperature required to avoid cold damage, and the reservoir temperature recovery time. Physical experiments first determine crude oil properties through crude oil viscosity-temperature and wax precipitation experiments. Breakthrough pressure experiments using cores are then conducted to determine the temperature at which reservoir cold damage occurs. Start-up pressure experiments determine the minimum temperature required to avoid damage. Relative permeability experiments determine the extent of cold damage's impact on reservoir flow capacity. Mercury injection experiments analyze the impact of cold damage on reservoir pore structure. Two-dimensional nuclear magnetic resonance (NMR) and laser confocal microscopy (LCM) experiments determine the reversibility of cold damage and the reversible temperature. Numerical simulations are then used to analyze the recovery time required for working fluids of varying volumes and temperatures to enter the formation.

[0014] The specific technical solutions are as follows:

[0015] A method for evaluating cold damage in a high pour point heavy oil reservoir comprises the following steps:

[0016] 1. Determine the physical properties of crude oil:

[0017] (1) Crude oil viscosity analysis: By analyzing the viscosity-temperature curve, the viscosity-temperature characteristics of crude oil can be obtained and the flow properties of crude oil at different temperatures can be evaluated.

[0018] (2) Crude oil wax precipitation analysis: Compare and analyze the amount of wax melted at different temperature points and analyze the recoverability of cold damage to the reservoir.

[0019] (3) Analysis of Crude Oil Thermophysical Parameters: The thermal conductivity of oil-bearing rocks is affected by the heat conduction between the rock solid phase and the oil phase in the pores. Experiments measuring the thermal conductivity of oil-bearing natural cores provide a basis for numerical simulations describing cold damage and wellbore duration.

[0020] 2. Determine the reservoir physical property range:

[0021] Based on reservoir conditions, rock property testing is conducted using cores obtained from drilling to determine the overall porosity and permeability of the core. Reservoir heterogeneity is calculated using the permeability coefficient of variation formula (1). Reservoir properties are then classified into several categories based on permeability and coefficient of variation (generally categorized as 0.2), including high permeability, medium permeability, low permeability, and ultra-low permeability.

[0022]

[0023] σ - coefficient of variation of permeability, dimensionless and expressed as a decimal;

[0024] - Average permeability of all samples, mD;

[0025] k i - permeability of the i-th sample, mD;

[0026] n-number of samples, in units.

[0027] 3. Determine if cold injury will occur:

[0028] Categorized core samples were subjected to a starting pressure test to analyze the changes in starting pressure at different temperatures. The presence of an inflection point in the starting pressure was used to determine when cold damage would occur in the reservoir. Based on the results of the reservoir overburden porosity test, the flow-pressure gradient inversion method or the pressure reduction method was determined. The starting pressure gradients (2.5 cm x 5 cm core samples) were tested at three permeability specifications and four temperatures.

[0029] 4. Determination of reservoir cold damage temperature:

[0030] After the rock is saturated with the wetting fluid, the non-wetting fluid must overcome the capillary resistance of the rock to expel the wetting fluid. The smaller the capillary radius of the rock, the greater the resistance and the higher the required breakthrough pressure. Pressurize the rock sample in the core holder and gradually increase the test pressure at the inlet. When the pressure causes the fluid to form a continuous mobile phase in the rock sample, the corresponding pressure difference between the inlet and outlet is the breakthrough pressure. Natural core columns were subjected to gas-phase breakthrough fracturing experiments using a core holder. The breakthrough pressures at different permeabilities and temperatures were determined, revealing the extent of damage from fracturing fluid cooling.

[0031] 5. Analysis of factors affecting seepage caused by cold damage:

[0032] Relative permeability experiments are used to determine the seepage capacity of oil and water at different temperatures and to assess the impact of cold damage on the seepage capacity of the reservoir. During the experiment, rather than injecting two fluids into the core simultaneously, the core is pre-saturated with one fluid and then displaced with the other fluid. During water flooding, the distribution of oil and water saturation in the porous medium is a function of distance and time, a process known as an unsteady process. In accordance with the requirements of the simulation conditions, constant pressure differential or constant velocity water flooding experiments are conducted on reservoir rock samples. The production of each fluid and the pressure differential across the sample are recorded at the outlet of the sample over time. The oil-water relative permeability is calculated using the "JBN" method, and a curve plotting the relationship between the oil-water relative permeability and water saturation is drawn.

[0033] Calculation formula:

[0034] Relative permeability and water saturation (oil-water calculation formula)

[0035]

[0036]

[0037]

[0038]

[0039]

[0040] Where:

[0041] f o (S w )—the oil content value, expressed as a decimal;

[0042] —Number of dimensionless cumulative oil recovery, expressed as a fraction of the pore volume;

[0043] —The dimensionless cumulative fluid production value, expressed as a fraction of the pore volume;

[0044] K ro —The numerical value of the oil phase relative permeability, expressed as a decimal;

[0045] K rw —The numerical value of the relative permeability of the water phase, expressed as a decimal;

[0046] I—relative injectivity value, also known as flowability ratio;

[0047] Q o —The value of the oil flow rate at the outlet of the sample at the initial moment, in cm 3 / s);

[0048] Q(t)—the liquid flow rate at the outlet of the rock sample at time t. In the constant rate method experiment, Q(t)=Q o , cm 3 / s;

[0049] Δp o —The value of the initial driving pressure difference, MPa;

[0050] Δp(t)—the displacement pressure difference at time t. In the constant pressure method experiment, Δp(t)=Δp o , MPa;

[0051] S ws —Numerical value of irreducible water saturation, expressed as a decimal;

[0052] S we —The numerical value of water saturation at the outlet end of the rock sample, expressed as a decimal.

[0053] 6. Impact of reservoir cold damage on pore structure:

[0054] CT experiments were used to clarify the changes in pore structure parameters caused by cold damage, including pore radius, duct radius, coordination number, and fractures. Nuclear magnetic resonance (NMR) experiments were used to analyze pore structure changes and the degree of phase confinement and mobility caused by cold damage. Oil-saturated cores at different permeabilities and temperatures were flooded with fracturing fluids, and CT and NMR experiments were used to analyze the changes in pore throat structure caused by cold damage.

[0055] 7. Numerical simulation of single well cold damage and well blocking law:

[0056] (1) Numerical simulation of fracturing fluid cooling damage

[0057] Experimental Methods: Based on the basic data of a single well in the reservoir, the PETRL software was used to establish a reservoir geological model. The reservoir numerical simulation software CMG was used to numerically simulate the cold damage caused by hydraulic fracturing in a single well and analyze the cold damage patterns. The factors affecting the cold damage caused by hydraulic fracturing fluid were numerically analyzed.

[0058] (2) Numerical simulation of well blocking law

[0059] Experimental Methods: Based on the basic data of a single well in the reservoir, a reservoir geological model was established using PETRL software. After numerically simulating cold damage from hydraulic fracturing in a single well using CMG, the reservoir numerical simulation software was used to analyze the recovery patterns of the temperature field after cold damage and numerically calculate the well blockage patterns. The numerical analysis analyzed the recovery patterns of the reservoir temperature field after cold damage from hydraulic fracturing fluid and its impact on productivity.

[0060] Compared with the prior art, the present invention has the following beneficial effects:

[0061] This research combines experimental physics simulation with numerical simulation to quantitatively and qualitatively analyze the extent and reversibility of reservoir cold damage, the minimum temperature required to avoid cold damage, and the reservoir temperature recovery time. Physical experiments include breakthrough pressure experiments to determine the temperature at which reservoir cold damage occurs, start-up pressure experiments to determine the minimum temperature required to avoid damage, relative permeability experiments to determine the extent of cold damage's impact on reservoir flow capacity, mercury injection experiments to analyze the impact of cold damage on reservoir pore structure, two-dimensional nuclear magnetic resonance (NMR) and laser confocal microscopy to determine the reversibility of cold damage and the reversibility temperature. Numerical simulations analyze the recovery time required for working fluids of varying fluid volumes and temperatures to enter the formation. This study determines the optimal working fluid temperature for high-pour point oil reservoir development and the recovery time after low-temperature working fluid enters the reservoir, ultimately reducing the development cost and improving development effectiveness of high-pour point oil reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0062] Figure 1 It is the oil phase starting pressure curve of cores with different permeabilities;

[0063] Figure 2 It is the relationship curve between seepage velocity and pressure gradient;

[0064] Figure 3 This is a graph showing the effect of temperature on the starting pressure of different cores;

[0065] Figure 4 It is a graph showing the relationship between temperature and breakthrough pressure gradient of different cores;

[0066] Figure 5 It is the technical roadmap of the present invention;

[0067] Figure 6 It is the crude oil viscosity-temperature curve 1, which represents the viscosity variation of crude oil without degassing;

[0068] Figure 7 It is the crude oil viscosity-temperature curve 2, which represents the viscosity change of crude oil after degassing;

[0069] Figure 8 is the cumulative wax precipitation amount change curve;

[0070] Figure 9 is the thermal conductivity-permeability relationship diagram;

[0071] Figure 10 is the thermal conductivity-porosity relationship diagram;

[0072] Figure 11 is the relationship curve between the starting pressure gradient and temperature;

[0073] Figure 12 This is a graph showing the starting pressure gradient changes for different cores at different temperatures;

[0074] Figure 13 It is the curve of the relationship between breakthrough pressure gradient and temperature;

[0075] Figure 14 It is the curve of formation temperature change caused by cold fluid injection;

[0076] Figure 15 The change of formation crude oil viscosity after injection of fluids at different temperatures for 2 hours;

[0077] Figure 16 This is the change in formation temperature 2 hours after the injection of fluids at different temperatures. DETAILED DESCRIPTION

[0078] The present invention is implemented in the following examples. Unless otherwise specified, the experimental methods used in the present invention are conventional methods, and the experimental equipment, materials, reagents, etc. used can be obtained from commercial channels.

[0079] Example 1

[0080] This example uses high-viscosity oil and natural cores from a block in Liaohe Oilfield to conduct cold damage experiments:

[0081] 1. Crude oil viscosity-temperature experiment:

[0082] By analyzing the viscosity-temperature curve, we can determine the viscosity-temperature characteristics of crude oil and assess its flow properties at different temperatures. The oil sample is considered extra-heavy, with a viscosity of 250,000 mPa·s at 30°C. The viscosity of a surface-degassed crude oil sample at a reservoir temperature of 65°C is 834.7 mPa·s. Above 41°C, the viscosity of crude oil decreases sharply and then levels off.

[0083] 2. Waxing experiment of crude oil:

[0084] The experimental study measured the cumulative wax precipitation of crude oil samples at temperatures ranging from low to high (25-75°C) and compared the wax melting rate at different temperatures to reveal the recoverability of reservoir cold damage. The experimental analysis showed that the wax precipitation temperature of crude oil was 62.77°C. Below 40°C, the cumulative wax precipitation rate increased sharply. Above 55°C, the wax precipitation rate dropped to zero. This confirmed that the critical temperature for cold damage is 55°C.

[0085] Table 1 Cumulative wax precipitation amount change table

[0086]

[0087] 3. Natural core oil thermal conductivity test equipment

[0088] The thermal conductivity of oil-bearing rocks is affected by heat conduction between the rock solid phase and the oil phase in the pores. Experimental measurements of the thermal conductivity of oil-bearing natural cores provide a basis for numerical simulations describing cold damage and wellbore duration. Reservoir cores are divided into three groups based on their physical properties: high, medium, and low permeability. These groups range from 25.75-56.74 mD (low permeability), 121.72-271.11 mD (medium permeability), and 325.91-452.24 mD (high permeability). Their thermal conductivities are also measured.

[0089] Low-permeability, low-porosity rocks have higher thermal conductivity, and rocks with high oil saturation have even higher thermal conductivity. The thermal conductivity of low-porosity, low-permeability natural rock cores ranges from 2.176 to 2.238 W / (m*K), the thermal conductivity of medium-permeability, medium-porosity natural rock cores ranges from 2.002 to 2.167 W / (m*K), and the thermal conductivity of high-permeability, high-porosity natural rock cores with oil saturation ranges from 2.081 to 2.281 W / (m*K).

[0090] Table 2 Experimental core physical property data

[0091]

[0092] 4. Start the pressure gradient test

[0093] Cold damage causes a decrease in reservoir temperature and reduced crude oil fluidity, making crude oil startup more difficult. The temperature limit for cold damage is determined based on the relationship between the oil-phase startup pressure gradient and temperature. When the fracturing fluid injection temperature is above 55°C, the oil-phase startup pressure gradient decreases more gradually with increasing temperature, and the difference in startup pressure gradients between different permeabilities is minimal. Cold damage primarily affects medium- and low-permeability cores (<300 mD), and the lower the permeability, the more pronounced the cold damage.

[0094] Table 3 Start-up pressure test data

[0095]

[0096] The experiment analyzed the starting pressure gradients of three cores with high, medium, and low permeabilities at temperatures of 45, 50, 55, 60, 65, 70, and 75°C. The results showed that the critical temperature for fracturing fluid cooling damage is 55°C.

[0097] Table 4 Statistics of startup pressure gradients for different cores at different temperatures

[0098]

[0099] Clarify the cold damage process and the difficulty of fracturing fluid injection. Reducing the reservoir temperature from 65°C to 55, 45, 35, and 25°C increases the breakthrough pressure of the fracturing fluid by 1.8, 3.2, 4.6, and 7.1 times, respectively.

[0100] 6. Non-steady-state phase permeability experimental method

[0101] The changing patterns of oil-water permeability parameters during reservoir cold damage recovery were clarified. During the wellbore blocking process, the near-wellbore formation temperature increased, indicating reservoir cold damage recovery. Temperatures above 55°C increased the oil-water two-phase flow span, particularly in low-permeability reservoirs. Low-permeability reservoirs saw a 105.92% increase, while medium- and high-permeability reservoirs saw an increase of approximately 30%.

[0102] Table 5 Statistics of oil-water relative permeability related parameters at different temperatures during the cold damage recovery process of low permeability, medium permeability and high permeability reservoirs

[0103]

[0104] 7. Numerical simulation

[0105] The grid in the I and J directions is 50×50 and 1m×1m in size. In the K direction, eight perforated intervals are simulated based on actual horizon information. Cold fluids at temperatures of 25°C, 30°C, 35°C, 40°C, 45°C, and 55°C are injected, respectively. Two layers are set above and below as thermal boundaries. With a reservoir temperature of 65°C, injecting cold fluids at temperatures of 25, 35, and 45°C for 2 hours takes 6, 4, and 3 hours, respectively, to return the formation temperature to 55°C. Recovery to 60°C takes 12, 9, and 7 hours. With an injected cold fluid at 55°C, recovery to 60°C takes 4 hours. The formation temperature change caused by cold water injection is primarily concentrated near the wellbore, within 5 meters.

[0106] Table 6 Statistics of the relationship between the temperature of the fluid entering the well and the recovery of the formation temperature

[0107]

[0108] Conclusion: The viscosity-temperature curve of the crude oil sample shows that the viscosity increases sharply with decreasing temperature below 41°C. Above 41°C, the viscosity gradually flattens with increasing temperature. This indicates that the pour point of the crude oil sample is 40°C. Wax precipitation experiments indicate that the wax precipitation temperature is 62.77°C, establishing the critical temperature of the cold fluid as 55°C. Comparison of the increase in cumulative wax precipitation indicates that wax precipitation damage increases below 40°C, significantly decreases between 40 and 55°C, and is minimal above 55°C. When the fracturing fluid injection temperature is above 55°C, the oil phase threshold pressure gradient decreases more gradually with increasing temperature, with minimal differences in threshold pressure gradients between different permeabilities. Cold damage primarily affects medium- and low-permeability cores (<300 mD), with lower permeabilities causing more pronounced cold damage. During the wellbore blocking process, the near-wellbore formation temperature increases, and reservoir cold damage is restored. Temperatures above 55°C increase the oil-water two-phase flow span, particularly in low-permeability reservoirs. Low-permeability reservoirs increased by 105.92%, while medium- and high-permeability reservoirs increased by approximately 30%. Reservoir temperature decreased from 65°C to 55, 45, 35, and 25°C, and the breakthrough pressure gradient of the fracturing fluid increased by 1.8, 3.2, 4.6, and 7.1 times, respectively. At a reservoir temperature of 65°C, when injected cold fluid at temperatures of 25, 35, and 45°C took 2 hours to recover to 55°C, respectively. Recovery to 60°C took 12, 9, and 7 hours. When injected cold fluid at 55°C took 4 hours to recover to 60°C. The change in formation temperature following cold water injection was primarily concentrated near the wellbore, within 5 meters.

[0109] The above is a schematic description of the present invention and its embodiments, which is not restrictive. The drawings show only one embodiment of the present invention, and the actual structure is not limited thereto. Therefore, if a person skilled in the art is inspired by this and, without departing from the purpose of the present invention, designs a structure and embodiment similar to this technical solution without inventiveness, they shall fall within the scope of protection of the present invention.

Claims

1. A method for evaluating cold damage of high-viscosity oil, characterized by: Using physical simulation and numerical simulation methods, the degree of reservoir cold damage, reversibility, the minimum temperature to avoid cold damage and the reservoir temperature recovery time are analyzed from both quantitative and qualitative aspects. The physical simulation first determines the crude oil properties through crude oil viscosity-temperature and wax precipitation experiments, then uses cores to conduct breakthrough pressure experiments to determine the occurrence temperature of reservoir cold damage, the start-up pressure experiment determines the minimum temperature to avoid damage, the relative permeability experiment determines the extent of the impact of cold damage on the reservoir seepage capacity, the mercury injection experiment analyzes the impact of cold damage on the reservoir pore structure, and the two-dimensional nuclear magnetic resonance experiment and laser confocal laser experiment determine whether the cold damage is reversible and the reversible temperature; numerical simulation is used to analyze the recovery time required for working fluids with different liquid volumes and different temperatures to enter the formation.

2. The method for evaluating cold damage of high pour point viscous oil according to claim 1, wherein: The following steps are involved: Step S1. Determine the physical properties of crude oil: (1) Crude oil viscosity analysis: By analyzing the viscosity-temperature curve, the viscosity-temperature characteristics of crude oil are obtained and the flow properties of crude oil at different temperatures are evaluated; (2) Crude oil wax precipitation analysis: Comparative analysis of wax melting at different temperature points to analyze the recoverability of reservoir cold damage; (3) Analysis of crude oil thermophysical parameters: The thermal conductivity of oil-bearing rocks is affected by the heat conduction between the rock solid phase and the oil phase in the pores. By measuring the thermal conductivity of oil-bearing natural cores, we can provide a basis for numerical simulation to describe cold damage and well blocking time. Step S2. Determine reservoir physical property intervals: Based on reservoir conditions, rock physical property testing is carried out using cores obtained from drilling to determine the overall porosity and permeability of the core. The reservoir heterogeneity is calculated using the permeability variation coefficient formula, and the reservoir physical properties are classified into several categories based on permeability and variation coefficient, such as high permeability, medium permeability, low permeability, and ultra-low permeability. Step S3. Determine whether cold injury will occur: Conduct a starting pressure test on the classified core samples to analyze the changes in starting pressure at different temperatures. Use the presence of an inflection point in the starting pressure to determine when cold damage will occur in the reservoir. Based on the results of the reservoir overburden porosity test, determine whether to use the flow-pressure gradient inversion method or the pressure reduction method. Step S4. Determine reservoir cold damage temperature: Pressurize the rock sample in the core holder and gradually increase the test pressure at the inlet. When the pressure causes the fluid to form a continuous mobile phase in the rock sample, the corresponding pressure difference between the inlet and outlet is the breakthrough pressure. Use the core holder to conduct gas-phase breakthrough fracturing experiments to determine the breakthrough pressure at different permeabilities and temperatures, and reveal the degree of damage caused by fracturing fluid cooling. Step S5. Analysis of factors affecting seepage due to cold damage: Relative permeability experiments are used to determine the seepage capacity of oil and water at different temperatures and to judge the impact of cold damage on reservoir seepage capacity; Step S6. Impact of reservoir cold damage on pore structure: Through CT experiments, the changes in pore structure parameters caused by cold damage were clarified. Through nuclear magnetic resonance experiments, the changes in pore structure and the degree of phase restraint and mobility caused by cold damage were analyzed. Oil-saturated cores with different permeabilities and temperatures were flooded with fracturing fluids, and CT and nuclear magnetic resonance experiments were used to analyze the changes in pore throat structure caused by cold damage. Step S7. Numerical simulation of single well cold damage and well blocking law: Based on the basic data of a single well in the reservoir, the PETRL software was used to establish a reservoir geological model. The reservoir numerical simulation software CMG was used to perform numerical simulation of cold damage caused by hydraulic fracturing of a single well, analyze the law of cold damage, and numerically analyze the factors affecting cold damage caused by hydraulic fracturing fluid. Based on the basic data of a single well in the reservoir, the PETRL software was used to establish a reservoir geological model. After numerical simulation of cold damage caused by hydraulic fracturing of a single well using the reservoir numerical simulation software CMG, the recovery law of the temperature field caused by cold damage was analyzed and the law of well blocking was numerically calculated. The recovery law of the temperature field of the blocked well reservoir after cold damage caused by hydraulic fracturing of the fracturing fluid and its impact on productivity were numerically analyzed.

3. The method for evaluating cold damage of high pour point viscous oil according to claim 2, wherein: The formula for the permeability variation coefficient in step S2 is: σ - coefficient of variation of permeability, dimensionless and expressed as a decimal; - Average permeability of all samples, mD; k i - permeability of the i-th sample, mD; n-number of samples, in units.

4. The method for evaluating cold damage of high pour point viscous oil according to claim 2, wherein: In step S3, three permeability specifications and starting pressure gradients at four temperatures are used for testing.

5. The method for evaluating cold damage of high pour point viscous oil according to claim 2, wherein: In step S4, the core holder is Natural core column.

6. The method for evaluating cold damage of high pour point viscous oil according to claim 2, wherein: In step S5, the relative permeability experiment does not involve injecting two fluids into the core simultaneously. Instead, the core is pre-saturated with one fluid and then displaced with the other fluid. During water-displacement, the distribution of oil and water saturation in the porous medium is a function of distance and time. This process is called an unsteady process. Based on the simulation conditions, a constant pressure differential or constant velocity water-displacement experiment is conducted on the reservoir rock sample. The production of each fluid and the pressure differential across the sample are recorded over time at the sample outlet. The oil-water relative permeability is calculated using the "JBN" method, and a curve plotting the relationship between the oil-water relative permeability and water saturation is drawn.

7. The method for evaluating cold damage of high pour point viscous oil according to claim 6, wherein: The calculation formulas for relative permeability and water saturation in step S5 are: Where: f o (S w )—the oil content value, expressed as a decimal; —Number of dimensionless cumulative oil recovery, expressed as a fraction of the pore volume; —The dimensionless cumulative fluid production value, expressed as a fraction of the pore volume; K ro —The numerical value of the oil phase relative permeability, expressed as a decimal; K rw —The numerical value of the relative permeability of the water phase, expressed as a decimal; I—relative injectivity value, also known as flowability ratio; Q o —The value of the oil flow rate at the outlet of the rock sample at the initial moment, in cm 3 / s); Q(t)—the liquid flow rate at the outlet of the rock sample at time t. In the constant rate method experiment, Q(t)=Q o , cm 3 / s; Δp o —The value of the initial driving pressure difference, MPa; Δp(t)—the displacement pressure difference at time t. In the constant pressure method experiment, Δp(t) = Δp o , MPa; S ws —Numerical value of irreducible water saturation, expressed as a decimal; S we —The numerical value of water saturation at the outlet end of the rock sample, expressed as a decimal.

8. The method for evaluating cold damage of high pour point viscous oil according to claim 2, wherein: The pore structure parameters in step S6 include pore radius, channel radius, coordination number, and cracks.

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